Note: Descriptions are shown in the official language in which they were submitted.
RECOVERY OF HEAVY OIL FROM A SUBTERRANEAN RESERVOIR
BACKGROUND
Field of Disclosure
[0001] The present disclosure relates to production of a bitumen product
from a
subterranean reservoir with improved control of asphaltene content and
improved bitumen
recovery in a solvent-based recovery process.
Description of Related Art
[0002] This section is intended to introduce various aspects of the art.
This discussion is
believed to facilitate a better understanding of particular aspects of the
present techniques.
Accordingly, it should be understood that this section should be read in this
light, and not
necessarily as admissions of prior art.
[0003] Modern society is greatly dependent on the use of hydrocarbon
resources for fuels
and chemical feedstocks. Subterranean rock formations that can be termed
"reservoirs" may
.. contain resources such as hydrocarbons that can be recovered. Removing
hydrocarbons from
the subterranean reservoirs depends on numerous physical properties of the
subterranean rock
formations, such as the permeability of the rock containing the hydrocarbons,
the ability of the
hydrocarbons to flow through the subterranean rock formations, and the
proportion of
hydrocarbons present, among other things.
[0004] Easily produced sources of hydrocarbons are dwindling, leaving less
conventional
sources to satisfy future needs. As the costs of hydrocarbons increase, less
conventional
sources become more economical. One example of less conventional sources
becoming more
economical is that of oil sand production. The hydrocarbons produced from less
conventional
sources may have relatively high viscosities, for example, ranging from 1000
centipoise (cP)
to 20 million cP with American Petroleum Institute (API) densities ranging
from 8 degree (0)
API, or lower, up to 200 API, or higher. The hydrocarbons recovered from less
conventional
sources may include heavy oil. However, the hydrocarbons produced from the
less
conventional sources may be difficult to recover using conventional
techniques. For example,
the heavy oil may be sufficiently viscous that economical production of the
heavy oil from a
subterranean formation (also referred to as a "subterranean reservoir" herein)
is precluded.
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[0005] Several conventional recovery processes, such as but not limited
to thermal
recovery processes, have been utilized to decrease the viscosity of the heavy
oil. Decreasing
the viscosity of the heavy oil may decrease a resistance of the heavy oil to
flow and/or permit
production of the heavy oil from the subterranean reservoir by piping,
flowing, and/or pumping
the heavy oil from the subterranean reservoir. While each of these recovery
processes may be
effective under certain conditions, each possess inherent limitations.
[0006] One of the conventional recovery processes utilizes steam
injection. The steam
injection may be utilized to heat the heavy oil to decrease the viscosity of
the heavy oil. Water
and/or steam may represent an effective heat transfer medium, but the pressure
required to
produce saturated steam at a desired temperature may limit the applicability
of steam injection
to high pressure operation and/or require a large amount of energy to heat the
steam.
100071 Another of the conventional recovery processes utilizes cold
and/or heated solvents.
Cold and/or heated solvents may be injected into a subterranean reservoir as
liquids and/or
vapors to decrease the viscosity of heavy oil present within the subterranean
reservoir.
Traditionally, pure (i.e., single-component), or at least substantially pure,
propane is injected
into the subterranean reservoir as the cold and/or heated solvent. The
injected propane may
dissolve the heavy oil, dilute the heavy oil, and/or transfer thermal energy
to the heavy oil.
Utilizing the cold and/or heated solvents may suffer from limited injection
temperature and/or
pressure operating ranges, and/or an inability to effectively decrease the
viscosity of the heavy
Oil.
[0008] In general, the conventional recovery processes may not decrease
the viscosity of
the heavy oil present within the subterranean reservoir. For example, certain
heavy oil may
not be soluble within the solvents utilized in a conventional recovery
process; a substantial
fraction of the heavy oil present in a subterranean reservoir may comprise
asphaltenes.
Asphaltenes may not be soluble in the solvent used and thus the asphaltenes
may not be
produced from the subterranean reservoir. Under certain conditions, it may be
desirable to
produce at least a fraction of the asphaltenes from the subterranean
reservoir; it may be
desirable to regulate an asphaltene content of the heavy oil produced from the
subterranean
reservoir.
[0009] A need exists for improved technology, including technology that may
address one
or more of the above described disadvantages. For example, a need exists for
regulating
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asphaltene production in a solvent-based recovery processes; a need exists for
selecting a
composition of a hydrocarbon solvent mixture.
SUMMARY
[0010] It is an object of the present disclosure to provide systems and
methods for
regulation of asphaltene production in a solvent-based recovery process and
selecting a
hydrocarbon solvent mixture composition of a hydrocarbon solvent mixture. It
is an object of
the present disclosure to provide systems and methods for improving bitumen
recovery in a
solvent-based recovery process by utilizing a near-azeotropic
steam/hydrocarbon solvent
.. injection process.
[0011] In an embodiment of the present invention is a process for
recovery of heavy oil
from a subterranean reservoir, the process comprising:
a) determining a target subterranean reservoir operating pressure;
b) determining a target subterranean reservoir operating temperature;
C) determining a target asphaltene content for a produced reservoir heavy oil
product stream from the subterranean reservoir;
d) adjusting the composition of a hydrocarbon solvent mixture to achieve the
asphaltene content in step c) under the conditions of steps a) and b);
e) determining the azeotropic/minimum dew point steam content of the
hydrocarbon solvent mixture in the vapor phase under the conditions of steps
a) and b);
f) at an actual subterranean reservoir operating pressure and an actual
subterranean
reservoir operating temperature, co-injecting a reservoir injection mixture in
the vapor phase
into the subterranean reservoir comprising steam and the hydrocarbon solvent
mixture, wherein
the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon
solvent
mixture is 70-110% of the azeotropic solvent molar fraction of the steam and
the hydrocarbon
solvent mixture as determined in step e);
g) recovering a reservoir heavy oil stream from the subterranean reservoir;
and
h) producing a bitumen product stream from the reservoir heavy oil product
stream.
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[0012] The foregoing has broadly outlined the features of the present
disclosure so that the
detailed description that follows may be better understood. Additional
features will also be
described herein.
DESCRIPTION OF THE DRAWINGS
[0013] These and other features, aspects and advantages of the present
disclosure will
become apparent from the following description and the accompanying drawings,
which are
briefly discussed below.
[0014] Figure 1 is a schematic representation of examples of a
hydrocarbon production
system.
[0015] Figure 2 is a plot of the phase behavior for a steam-hexane
system.
[0016] Figure 3 is a series of contour plots comparing reservoir
properties for heated
pentane (Cs H-VAPEX) and heated pentane with steam at the azeotropic
concentration (C5
Azeotropic H-VAPEX), at the same operating pressure.
[0017] Figure 4 is a graph of cumulative solvent to oil ratio (CS010R)
versus time for
H-VAPEX and Azeotropic H-VAPEX utilizing C5 and C7 injection.
[0018] Figure 5 is a graph of cumulative produced oil over retained
solvent versus time for
Heated Vapex and Azeotropic H-VAPEX utilizing C5 and C7 injection.
[0019] Figure 6 is a graph of oil recovery versus time for H-VAPEX and
Azeotropic Heated
Vapex utilizing C5 and C7 injection.
[0020] Figure 7 is a graph of semi-azeotropic behavior of a steam-
multicomponent solvent
(diluent) system.
[0021] Figure 8 is a graph of cumulative solvent to oil ratio (CS010R)
versus time in high
and low initial water saturation reservoir conditions.
[0022] Figure 9 is a graph of produced oil to retained solvent versus time
in high and low
initial water saturation reservoir conditions.
[0023] Figure 10 is a graph of collective dew point temperature plots for
vapor mixtures of
individual hydrocarbon solvents of C4-C9 with water as a function of solvent
mole fraction.
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[0024] Figure 11 is a bar graph illustrating heavy end component
deposition within a
subterranean reservoir for various single-component hydrocarbon solvents.
[0025] Figure 12 is a table illustrating an average saturation
temperature for three different
hydrocarbon solvent mixtures.
[0026] Figure 13 is a bar graph illustrating heavy end component deposition
within the
subterranean reservoir for the three different hydrocarbon solvent mixtures of
Figure 12.
DETAILED DESCRIPTION
[0027] For the purpose of promoting an understanding of the principles of
the disclosure,
to reference will now be made to the features illustrated in the drawings and
specific language
will be used to describe the same. It will nevertheless be understood that no
limitation of the
scope of the disclosure is thereby intended. Any alterations and further
modifications, and any
further applications of the principles of the disclosure as described herein,
are contemplated as
would normally occur to one skilled in the art to which the disclosure
relates. It will be apparent
to those skilled in the relevant art that some features that are not relevant
to the present
disclosure may not be shown in the drawings for the sake of clarity.
10028] At the outset, for ease of reference, certain terms used in this
application and their
meanings as used in this context are set forth. To the extent a term used
herein is not defined
below, it should be given the broadest definition persons in the pertinent art
have given that
term as reflected in at least one printed publication of issued patent.
Further, the present
techniques are not limited by the usage of the terms shown below, as all
equivalents, synonyms,
new developments, and terms or processes that serve the same or a similar
purpose are
considered to be within the scope of the present disclosure.
[0029] A "hydrocarbon" is an organic compound that primarily includes the
elements
hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number
of other
elements may be present in small amounts. Hydrocarbons generally refer to
components found
in heavy oil or in oil sands. However, the techniques described herein are not
limited to heavy
oils, but may also be used with any number of other subterranean reservoirs.
Hydrocarbon
compounds may be aliphatic or aromatic, and may be straight chained, branched,
or partially
or fully cyclic.
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100301 "Bitumen" is a naturally occurring heavy oil material. Generally,
it is the
hydrocarbon component found in oil sands. Bitumen can vary in composition
depending upon
the degree of loss of more volatile components. It can vary from a very
viscous, tar-like, semi-
solid material to solid forms. The hydrocarbon types found in bitumen can
include aliphatics,
aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt.)% aliphatics (which can range from 5 wt.% - 30 wt.%, or
higher);
19 wt.% asphaltenes (which can range from 5 wt.% - 30 wt.%, or higher);
30 wt.% aromatics (which can range from 15 wt.% - 50 wt.%, or higher);
32 wt.% resins (which can range from 15 wt.% - 50 wt.%, or higher); and
some amount of sulfur (which can range in excess of 7 wt.%).
100311 The percentage of the hydrocarbon types found in bitumen can vary.
In addition
bitumen can contain some water and nitrogen compounds ranging from less than
0.4 wt.% to
in excess of 0.7 wt.%. The metals content, while small, may be removed to
avoid
contamination of synthetic crude oil. Nickel can vary from less than 75 ppm
(parts per million)
to more than 200 ppm. Vanadium can range from less than 200 ppm to more than
500 ppm.
[0032] The term "heavy oil" includes bitumen, as well as lighter
materials that may be
found in a sand or carbonate reservoir. "Heavy oil" includes oils that are
classified by the
American Petroleum Institute (API), as heavy oils, extra heavy oils, or
bitumens. Thus the
term "heavy oil" includes bitumen. Heavy oil may have a viscosity of about
1000 centipoise
(cP) or more, 10,000 cP or more, 100,000 cP or more or 1,000,000 cP or more.
In general, a
heavy oil has an API gravity between 22.3 API (density of 920 kilograms per
meter cubed
(kg/m') or 0.920 grams per centimeter cubed (g/cm3)) and 10.0 API (density of
1,000 kg/m3
or 1 g/cm3). An extra heavy oil, in general, has an API gravity of less than
10.0 API (density
greater than 1,000 kg/m3 or greater than 1 g/cm3). For example, a source of
heavy oil includes
oil sand or bituminous sand, which is a combination of clay, sand, water, and
bitumen. The
recovery of heavy oils is based on the viscosity decrease of fluids with
increasing temperature
or solvent concentration. Once the viscosity is reduced, the mobilization of
fluids by steam,
hot water flooding, or gravity is possible. The reduced viscosity makes the
drainage quicker
and therefore directly contributes to the recovery rate. A heavy oil may
include heavy end
components and light end components.
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100331 The term -asphaltenes" or "asphaltene content" refers to pentane
insolubles (or the
amount of pentane insoluble in a sample) according to ASTM D3279. Other
examples of
standard ASTM asphaltene tests include ASTM test numbers D4055, D6560, and
D7061.
[0034] "Heavy end components" in heavy oil may comprise a heavy viscous
liquid or solid
made up of heavy hydrocarbon molecules. Examples of heavy hydrocarbon
molecules include,
but are not limited to, molecules having greater than or equal to 30 carbon
atoms (C30+). The
amount of molecules in the heavy hydrocarbon molecules may include any number
within or
bounded by the preceding range. The heavy viscous liquid or solid may be
composed of
molecules that, when separated from the heavy oil, have a higher density and
viscosity than a
to density and viscosity of the heavy oil containing both heavy end
components and light end
components. For example, in Athabasca bitumen, about 70 weight (wt.) % of the
bitumen
contains C30+ molecules with about 18 wt. % of the Athabasca bitumen being
classified as
asphaltenes. The heavy end components may include asphaltenes in the form of
solids or
viscous liquids.
[0035] "Light end components" in heavy oil may comprise those components in
the heavy
oil that have a lighter molecular weight than heavy end components. The light
end components
may include what can be considered to be medium end components. Examples of
light end
components and medium end components include, but are not limited to, light
and medium
hydrocarbon molecules having greater than or equal to 1 carbon atom and less
than 30 carbon
atoms. The amount of molecules in the light and medium end components may
include any
number within or bounded by the preceding range. The light end components and
medium end
components may be composed of molecules that have a lower density and
viscosity than a
density and viscosity of heavy end components from the heavy oil.
[0036] A "fluid" includes a gas or a liquid and may include, for example,
a produced or
native reservoir hydrocarbon, an injected mobilizing fluid, hot or cold water,
or a mixture of
these among other materials. "Vapor" refers to steam, wet steam, and mixtures
of steam and
wet steam, any of which could possibly be used with a solvent and other
substances, and any
material in the vapor phase.
[0037] "Facility" or "surface facility" is a tangible piece of physical
equipment through
which hydrocarbon fluids are either produced from a subterranean reservoir or
injected into a
subterranean reservoir, or equipment that can be used to control production or
completion
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operations. In its broadest sense, the term facility is applied to any
equipment that may be
present along the flow path between a subterranean reservoir and its delivery
outlets. Facilities
may comprise production wells, injection wells, well tubulars, wellbore head
equipment,
gathering lines, manifolds, pumps, compressors, separators, surface flow
lines, steam
generation plants, processing plants, and delivery outlets. In some instances,
the term "surface
facility" is used to distinguish from those facilities other than wells.
[0038] "Pressure" is the force exerted per unit area by the gas on the
walls of the volume.
Pressure may be shown in this disclosure as pounds per square inch (psi),
kilopascals (kPa) or
megapascals (MPa). "Atmospheric pressure" refers to the local pressure of the
air. "Absolute
pressure" (psia) refers to the sum of the atmospheric pressure (14.7 psia at
standard conditions)
plus the gauge pressure. "Gauge pressure" (psig) refers to the pressure
measured by a gauge,
which indicates only the pressure exceeding the local atmospheric pressure
(i.e., a gauge
pressure of 0 psig corresponds to an absolute pressure of 14.7 psia). The term
"vapor pressure"
has the usual thermodynamic meaning. For a pure component in an enclosed
system at a given
pressure, the component vapor pressure is essentially equal to the total
pressure in the system.
Unless otherwise specified, the pressures in the present disclosure are
absolute pressures.
[0039] A "subterranean reservoir- is a subsurface rock or sand reservoir
from which a
production fluid, or resource, can be harvested. A subterranean reservoir may
interchangeably
be referred to as a subterranean formation. The subterranean formation may
include sand,
granite, silica, carbonates, clays, and organic matter, such as bitumen, heavy
oil (e.g., bitumen),
oil, gas, or coal, among others. Subterranean reservoirs can vary in thickness
from less than
one foot (0.3048 meters (m)) to hundreds of feet (hundreds of meters). The
resource is
generally a hydrocarbon, such as a heavy oil impregnated into a sand bed.
[0040] "Thermal recovery processes" include any type of hydrocarbon
recovery process
that uses a heat source to enhance the recovery, for example, by lowering the
viscosity of a
hydrocarbon. The processes may use injected mobilizing fluids, such as but not
limited to hot
water, wet steam, dry steam, or solvents alone, or in any combination, to
lower the viscosity of
the hydrocarbon. Any of the thermal recovery processes may be used in concert
with solvents.
For example, thermal recovery processes may include cyclic steam stimulation
(CSS), steam
assisted gravity drainage (SAGD), steam flooding, in-situ combustion and other
such
processes.
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[0041] -Solvent-based recovery processes- include any type of hydrocarbon
recovery
process that uses a solvent, at least in part, to enhance the recovery, for
example, by diluting or
lowering a viscosity of the hydrocarbon. Solvent-based recovery processes may
be used in
combination with other recovery processes, such as, for example, thermal
recovery processes.
In solvent-based recovery processes, a solvent is injected into a subterranean
reservoir. The
solvent may be heated or unheated prior to injection, may be a vapor or liquid
and may be
injected with or without steam. Solvent-based recovery processes may include,
but are not
limited to, solvent assisted cyclic steam stimulation (SA-CSS), solvent
assisted steam assisted
gravity drainage (SA-SAGD), solvent assisted steam flood (SA-SF), vapor
extraction process
(VAPEX), heated vapor extraction process (H-VAPEX), cyclic solvent process
(CSP), heated
cyclic solvent process (H-CSP), solvent flooding, heated solvent flooding,
liquid extraction
process, heated liquid extraction process, solvent-based extraction recovery
process (SEP),
thermal solvent-based extraction recovery processes (TSEP), and any other such
recovery
process employing solvents either alone or in combination with steam. A
solvent-based
recovery process may be a thermal recovery process if the solvent is heated
prior to injection
into the subterranean reservoir. The solvent-based recovery process may employ
gravity
drainage.
[0042] Steam to Oil Ratio ("SOR") is the ratio of a volume of steam (in
cold water
equivalents) required to produce a volume of oil. Cumulative SOR ("CSOR") is
the average
volume of steam (in cold water equivalents) over the life of the operation
required to produce
a volume of oil. Instantaneous ("ISOR") is the instantaneous rate of steam (in
cold water
equivalents) required to produce a volume of oil. SOR, CSOR, and ISOR are
calculated at
standard temperature and pressure ("STP", 15 C and 100kPa or 60 F and 14.696
psi).
[0043] Likewise, Solvent to Oil Ratio (-SciOR'') is the ratio of a volume
of solvent (in cold
liquid equivalents) required to produce a volume of oil. Cumulative SoiOR
("CSolOR") is the
average volume of solvent (in cold liquid equivalents) over the life of the
operation required to
produce a volume of oil. Instantaneous ("ISolOR'') is the instantaneous rate
of solvent required
to produce a volume of oil. 5010R, CSolOR, and ISolOR are calculated at STP.
[0044] "Azeotrope" means the thermodynamic azeotrope as described further
herein.
[0045] A "wellbore" is a hole in the subsurface made by drilling or
inserting a conduit into
the subsurface. A wellbore may have a substantially circular cross section or
any other cross-
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sectional shape, such as an oval, a square, a rectangle, a triangle, or other
regular or irregular
shapes. The term "well,- when referring to an opening in the formation or
reservoir, may be
used interchangeably with the term "wellbore." Further, multiple pipes may be
inserted into a
single wellbore, for example, as a liner configured to allow flow from an
outer chamber to an
inner chamber.
[0046] "Permeability- is the capacity of a structure to transmit fluids
through the
interconnected pore spaces of the structure. The customary unit of measurement
for
permeability is the milliDarcy (mD).
[0047] "Reservoir matrix" refers to the solid porous material forming the
structure of the
to subterranean reservoir. The subterranean reservoir is composed of the
solid reservoir matrix,
typically rock or sand, around pore spaces in which resources such as heavy
oil may be located.
The porosity and permeability of a subterranean reservoir is defined by the
percentage of
volume of void space in the rock or sand reservoir matrix that potentially
contains resources
and water.
[0048] The term "existing- as it may refer to the temperature, the
pressure, an asphaltene
content, density, viscosity, composition, or mixture component content
(collectively the
"variables-) as used herein, including the claims, refers to the value of the
particular variable
as it exists during the operating window of analysis and/or measuring of the
variables in order
to determine changes to be made in the process.
[0049] The term 'target" as it may refer to the temperature, the pressure,
an asphaltene
content, density, viscosity, composition, or mixture component content
(collectively the
"variables") as used herein, including the claims, refers to the projected
value of particular
variable as would be modified or maintained in order to determine changes to
be made in the
process.
[0050] The term "actual" as it may refer to the temperature, the pressure,
an asphaltene
content, density, viscosity, composition, or mixture component content
(collectively the
"variables") as used herein, including the claims, refers to the actual value
of particular variable
as modified or maintained at the time of revisions in the variable(s) in the
process. The actual
value of a variable may be the same or different from either the existing
value or the target
value of that particular variable.
[0051] A "solvent extraction chamber" is a region of a subterranean
reservoir containing
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heavy oil that forms around a well that is injecting solvent into the
subterranean reservoir. The
solvent extraction chamber has a temperature and a pressure that is generally
at or close to a
temperature and pressure of the solvent injected into the subterranean
reservoir. The solvent
extraction chamber may form when heavy oil has, due to heat from the solvent,
dissolution
within the solvent, combination with the solvent, and/or the action of
gravity, at least partially
mobilized through the pore spaces of the reservoir matrix. The mobilized heavy
oil may be at
least partially replaced in the pore spaces by solvent, thus forming the
solvent chamber. In
practice, layers in the subterranean reservoir containing heavy oil may not
necessarily have
pore spaces that contain 100 percent (%) heavy oil and may contain only 70 -
80 volume (vol.)
1 % heavy oil with the remainder possibly being water. A water and/or gas
containing layer in
the subterranean reservoir may comprise 100% water and/or gas in the pore
spaces, but
generally contains 5 - 70 vol.% gas and 20 - 30 vol.% water with any remainder
possibly being
heavy oil.
[0052] A "vapor chamber" is a solvent extraction chamber that includes a
vapor, or
vaporous solvent. Thus, when the solvent is injected into the subterranean
reservoir as a vapor,
a vapor chamber may be formed around the well.
[0053] A "compound that has five or more carbon atoms" or "C5+"may
include any
suitable single chemical species that may include five or more carbon atoms. A
"compound
that has five or more carbon atoms" also may include any suitable mixture of
chemical species.
Each of the chemical species in the mixture of chemical species may include
five or more
carbon atoms and each of the chemical species in the mixture of chemical
species also may
include the same number of carbon atoms as the other chemical species in the
mixture of
chemical species. For example, a compound that has five carbon atoms may
include a pentane,
n-pentane, a branched pentane, cyclopentane, a pentene, n-pentene, a branched
pentene,
cyclopentene, a pentyne, n-pentyne, a branched pentyne, cyclopentyne,
methylbutane,
dimethylpropane, ethylpropane, and/or any other hydrocarbon with five carbon
atoms. A
compound with six carbon atoms, seven carbon atoms, or eight carbon atoms may
include a
single chemical species with six carbon atoms, seven carbon atoms, or eight
carbon atoms,
respectively, and/or may include a mixture of chemical species that each
include six carbon
atoms, seven carbon atoms, or eight carbon atoms, respectively.
[0054] The terms "approximately," "about," "substantially," and similar
terms are intended
to have a broad meaning in harmony with the common and accepted usage by those
of ordinary
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skill in the art to which the subject matter of this disclosure pertains. It
should be understood
by those of skill in the art who review this disclosure that these terms are
intended to allow a
description of certain features described and claimed without restricting the
scope of these
features to the precise numeral ranges provided. Accordingly, these terms
should be interpreted
as indicating that insubstantial or inconsequential modifications or
alterations of the subject
matter described and are considered to be within the scope of the disclosure.
These terms when
used in reference to a quantity or amount of a material, or a specific
characteristic of the
material, refer to an amount that is sufficient to provide an effect that the
material or
characteristic was intended to provide. The exact degree of deviation
allowable may in some
cases depend on the specific context.
100551 The articles "the", "a" and "an" are not necessarily limited to
mean only one, but
rather are inclusive and open ended so as to include, optionally, multiple
such elements.
100561 As used herein, the phrase "at least one," in reference to a list
of one or more entities
should be understood to mean at least one entity selected from any one or more
of the entity in
the list of entities, but not necessarily including at least one of each and
every entity specifically
listed within the list of entities and not excluding any combinations of
entities in the list of
entities. This definition also allows that entities may optionally be present
other than the
entities specifically identified within the list of entities to which the
phrase "at least one" refers,
whether related or unrelated to those entities specifically identified. Thus,
as a non-limiting
example, "at least one of A and B" (or, equivalently, "at least one of A or
B," or, equivalently
"at least one of A and/or B") may refer, to at least one, optionally including
more than one, A,
with no B present (and optionally including entities other than B); to at
least one, optionally
including more than one, B, with no A present (and optionally including
entities other than A);
to at least one, optionally including more than one, A, and at least one,
optionally including
more than one, B (and optionally including other entities). In other words,
the phrases "at least
one," "one or more," and "and/or" are open-ended expressions that are both
conjunctive and
disjunctive in operation. For example, each of the expressions "at least one
of A, B and C,"
"at least one of A, B, or C," "one or more of A, B, and C," "one or more of A,
B, or C" and
"A, B, and/or C" may mean A alone, B alone, C alone, A and B together, A and C
together, B
and C together, A, B and C together, and optionally any of the above in
combination with at
least one other entity.
[0057] As used herein, the term "and/or" placed between a first entity
and a second entity
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F
means one of (1) the first entity, (2) the second entity, and (3) the first
entity and the second
entity. Multiple entities listed with "and/or" should be construed in the same
manner, i.e., "one
or more" of the entities so conjoined. Other entities may optionally be
present other than the
entities specifically identified by the "and/or" clause, whether related or
unrelated to those
entities specifically identified. Thus, as a non-limiting example, a reference
to "A and/or B,"
when used in conjunction with open-ended language such as "comprising" may
refer to A only
(optionally including entities other than B); to B only (optionally including
entities other than
A); to both A and B (optionally including other entities). These entities may
refer to elements,
actions, structures, steps, operations, values, and the like.
[0058] As used herein the terms "adapted" and "configured" mean that the
element,
component, or other subject matter is designed and/or intended to perform a
given function.
Thus, the use of the terms "adapted" and "configured" should not be construed
to mean that a
given element, component, or other subject matter is simply "capable of"
performing a given
function but that the element, component, and/or other subject matter is
specifically selected,
created, implemented, utilized, programmed, and/or designed for the purpose of
performing
the function. It is also within the scope of the present disclosure that
elements, components,
and/or other recited subject matter that is recited as being adapted to
perform a particular
function may additionally or alternatively be described as being configured to
perform that
function, and vice versa.
[0059] As used herein, the phrase, "for example," the phrase, "as an
example," and/or
simply the term "example," when used with reference to one or more components,
features,
details, structures, embodiments, and/or methods according to the present
disclosure, are
intended to convey that the described component, feature, detail, structure,
embodiment, and/or
method is an illustrative, non-exclusive example of components, features,
details, structures,
embodiments, and/or methods according to the present disclosure. Thus, the
described
component, feature, detail, structure, embodiment, and/or method is not
intended to be limiting,
required, or exclusive/exhaustive; and other components, features, details,
structures,
embodiments, and/or methods, including structurally and/or functionally
similar and/or
equivalent components, features, details, structures, embodiments, and/or
methods, are also
within the scope of the present disclosure.
[0060] Any of the ranges disclosed may include any number within and/or
bounded by the
range given.
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[0061] In the illustrative figures herein, in general, elements that are
likely to be included
are illustrated in solid lines, while elements that are optional are
illustrated in dashed lines.
However, elements that are shown in solid lines may not be essential. Thus, an
element shown
in solid lines may be omitted without departing from the scope of the present
disclosure.
[0062] Figures 1-13 provide illustrative, non-exclusive examples of systems
according to
the present disclosure, components of systems, data that may be utilized to
select a composition
of a hydrocarbon solvent mixture and or a reservoir injection mixture that may
be utilized with
systems, and/or methods, according to the present disclosure, of operating
and/or utilizing
systems. Elements that serve a similar, or at least substantially similar,
purpose are labeled
with like numbers in each of Figures 1-13, and these elements may not be
discussed in detail
herein with reference to each of Figures 1-13. Similarly, all elements may not
be labeled in
each of Figures 1-13, but associated reference numerals may be utilized for
consistency.
Elements, components, and/or features that are discussed herein with reference
to one or more
of Figures 1-13 may be included in and/or utilized with any of Figures 1-13
without departing
from the scope of the present disclosure.
[0063] Figure 1 is a schematic representation of a hydrocarbon production
system 10 that
may be utilized with, may be included in, and/or may include the systems and
methods
according to the present disclosure. Hydrocarbon production system 10 may
include an
injection well 30 and a production well 70 that extend within a subterranean
reservoir 24 that
is present within a subsurface region 22 and/or that extend between a surface
region 20 and the
subterranean reservoir 24. Hydrocarbon production system 10 may include a
surface facility
40. Surface facility 40 may be configured to receive a reservoir heavy oil
product stream 72
from production well 70. A reservoir heavy oil product stream 72 may be
produced from the
subterranean reservoir 24. Surface facility 40 may be configured to provide a
reservoir
injection mixture 32 to injection well 30.
[0064] The reservoir injection mixture 32 may be in liquid form, vapor
form, or both. The
reservoir injection mixture preferably is comprised of a steam and hydrocarbon
solvent
mixture. When the hydrocarbon solvent mixture is a vaporous hydrocarbon
solvent mixture
32, the solvent-based recovery process may be referred to as, or may be, a
vapor extraction
process (VAPEX). Hydrocarbon solvent mixture 32 also may be, or may be
referred to as, a
liquid-vapor hydrocarbon solvent mixture 32 that includes a liquid and a
vapor. In a preferred
embodiment, the steam and hydrocarbon solvent mixture is within 30%+/-, 20%+/-
, or 10%+/-
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of the azeotropic solvent molar fraction of the steam and the solvent as
measured at the
reservoir operating pressure. Alternatively, the steam and hydrocarbon solvent
mixture is 70-
110%, 70-100%, 80-100%, or 90 to 100% of the azeotropic solvent molar fraction
of the steam
and the solvent as measured at the reservoir operating pressure. In another
preferred
embodiment, the reservoir injection mixture is comprised of at least 80% by
weight of the
steam and hydrocarbon solvent mixture. In other preferred embodiments, the
reservoir injection
mixture is comprised of at least 90% or 95% by weight of the steam and
hydrocarbon solvent
mixture, more preferably, is comprised essentially of the steam and
hydrocarbon solvent
mixture.
100651 In preferred embodiments, at least 90%, at least 95%, or essentially
all (by weight)
of the reservoir injection mixture is injected into the subterranean reservoir
in vapor form.
100661 When the solvent-based recovery process is performed using heated
solvent, the
solvent-based recovery process may be referred to as a high temperature
solvent (and/or vapor)
solvent-based recovery process. The heated solvent may be injected into the
subterranean
reservoir at an injection temperature and an injection pressure. The injection
temperature may
be at, or near, a saturation temperature for the heated solvent at the
injection pressure. When
more than one solvent is utilized, the extraction process may be referred to
as a multi-solvent-
based recovery process and/or a multi-component solvent-based recovery
process, which, at
elevated temperatures, may be referred to as a high temperature multi-
component solvent-
based recovery process, which may be a high temperature multi-component vapor
extraction
process.
[0067] Once provided to subterranean reservoir 24, reservoir injection
mixture 32 may
combine with bituminous hydrocarbon deposit 25 within a solvent extraction
chamber 60, may
dissolve in bituminous hydrocarbon deposit 25, and/or may dissolve bituminous
hydrocarbon
deposit 25, thereby decreasing the viscosity of the bituminous hydrocarbon
deposit. When
reservoir injection mixture 32 is a vaporous hydrocarbon solvent mixture,
solvent extraction
chamber 60 may be referred to as a vapor chamber 60. The vaporous hydrocarbon
solvent
mixture may condense within vapor chamber 60. When reservoir injection mixture
32
condenses, the hydrocarbon solvent mixture may release latent heat (or latent
heat of
condensation), transfer thermal energy to the subterranean reservoir, and/or
generate a
condensate 34. Condensation of the reservoir injection mixture 32 may heat a
bituminous
hydrocarbon deposit 25 that may be present within the subterranean reservoir,
thereby
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decreasing a viscosity of the bituminous hydrocarbon deposit.
10068] The bituminous hydrocarbon deposit 25 may include bitumen, gaseous
hydrocarbons, asphaltenes, and/or water. The reservoir injection mixture 32
and/or condensate
34 also may combine with, mix with, be dissolved in, dissolve, and/or dilute
bituminous
hydrocarbon deposit 25, further decreasing the viscosity of the bituminous
hydrocarbon
deposit.
[0069] The energy transfer between the reservoir injection mixture 32 and
bituminous
hydrocarbon deposit 25 and/or the mixing of reservoir injection mixture 32
and/or condensate
34 with bituminous hydrocarbon deposit 25 may generate reduced-viscosity
hydrocarbons 74,
which may flow to production well 70. After flowing to production well 70, a
reservoir heavy
oil product stream 72 is produced from the subterranean reservoir. The reduced-
viscosity
hydrocarbons 74 may have a lower viscosity than the hydrocarbons within the
subsurface
reservoir 24 had before the reservoir injection mixture 32 was injected into
the subterranean
reservoir 24. The reservoir heavy oil product stream 72 may comprise reduced-
viscosity
hydrocarbons 74, asphaltenes, gaseous hydrocarbons, water, reservoir injection
mixture 32,
and/or condensate 34 in any suitable ratio and/or relative proportion.
100701 The systems and methods according to the present disclosure may be
utilized to
control and/or regulate a product hydrocarbon stream composition of the
reservoir heavy oil
product stream 72. The systems and methods according to the present disclosure
may be
utilized to control and/or regulate a portion of the bituminous hydrocarbon
deposit 25 that is
produced from the subterranean reservoir 24. A hydrocarbon solvent mixture
composition of
the hydrocarbon solvent mixture may be controlled, regulated, and/or varied
such that a first
portion of the bituminous hydrocarbon deposit becomes reduced-viscosity
hydrocarbons 74
and/or is produced with the reservoir heavy oil product stream 72. The
hydrocarbon solvent
mixture composition may be controlled, regulated, and/or varied such that a
second portion of
the bituminous hydrocarbon deposit remains within the subterranean reservoir,
does not
become reduced-viscosity hydrocarbons 74, and/or is not produced with the
reservoir heavy oil
product stream 72. The first portion of the bituminous hydrocarbon deposit may
have a lower
asphaltene content than the bituminous hydrocarbon deposit and may be referred
to as an
upgraded portion of the bituminous hydrocarbon deposit. The second portion of
the bituminous
hydrocarbon deposit may have a higher asphaltene content than the bituminous
hydrocarbon
deposit and also may be referred to as a retained portion of the bituminous
hydrocarbon deposit.
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The first portion of the bituminous hydrocarbon deposit may be different from
the second
portion of the bituminous hydrocarbon deposit.
[0071] The systems and methods according to the present disclosure may be
discussed in
the context of determining, adjusting, and/or regulating the asphaltene
content of the product
hydrocarbon stream. It is to be understood that adjusting and/or regulating
the asphaltene
content of the product hydrocarbon stream may include regulating the
proportion of the
asphaltenes from the bituminous hydrocarbon deposit that are retained within
the subterranean
reservoir and/or that are not produced with the product hydrocarbon stream.
[0072] Surface facility 40 may process the reservoir heavy oil product
stream 72 and/or
may separate the reservoir heavy oil product stream 72 into one or more
component streams
prior to the product hydrocarbon stream being conveyed from the surface
facility 40. Surface
facility 40 may separate reservoir heavy oil product stream 72 into a bitumen
product stream
42, a gaseous hydrocarbon product stream 44, an asphaltene product stream 48,
a separated
surplus solvent stream 49, and/or a water product stream 46, which may include
water 29. The
bitumen product stream 42 may include bitumen and/or asphaltenes. The gaseous
hydrocarbon
product stream 44 may include gaseous hydrocarbons. The asphaltene product
stream 48 may
include asphaltenes. The separated solvent stream 49 may include a portion of
hydrocarbon
solvent mixture 32 that was produced with the reservoir heavy oil product
stream 72. The
surplus solvent stream 49 may be referred to as an undesired solvent stream,
an unwanted
solvent stream, and/or an excess solvent stream. Surplus solvent stream 49 may
be generated
as a result of adjustments to the hydrocarbon solvent mixture composition.
Surplus solvent
stream 49 may be generated as a result of removing some of the solvents in the
reservoir heavy
oil product stream 72 that are not wanted or desired to be in the hydrocarbon
solvent mixture
35 or the reservoir injection mixture 32.
[0073] Surface facility 40 may generate a hydrocarbon solvent mixture 35
from any
suitable source. Surface facility 40 may receive a supplemental solvent stream
31 and/or may
supply at least a portion of the hydrocarbon solvent mixture 35 recovered from
the reservoir
heavy oil product stream 72 as a part of the reservoir injection stream 32 to
injection well 30.
Surface facility 40 may separate at least a portion of gaseous hydrocarbon
product stream 44,
hydrocarbon solvent mixture 35, and/or condensate 34 from the reservoir heavy
oil product
stream 72. Surface facility 40 may recycle and/or re-inject a portion of the
gaseous
hydrocarbon product stream 44, separated hydrocarbon solvent mixture 35,
and/or separated
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condensate 34 into injection well 30 as components of the reservoir injection
mixture 32. The
hydrocarbon solvent mixture 35 may additionally include a supplemental solvent
stream 31.
The composition of the supplemental solvent stream 31 may be similar in
composition to the
hydrocarbon solvent mixture 35 wherein its main purpose is to add additional
solvent to the
hydrocarbon solvent mixture 35 for the reservoir injection mixture 32.
Alternatively, the
supplemental solvent stream 31 may be tailored to adjust the composition of
the overall
hydrocarbon solvent mixture 35 for the reservoir injection mixture 32, as well
as additionally
supply additional solvent to the overall process to make up for losses in the
subterranean
reservoir and/or losses due to the surface facility processing and solvent
recovery.
[0074] Conventional recovery processes that utilize an injected vapor
stream to decrease
the viscosity of hydrocarbons may utilize a pure (i.e., single-component), or
at least
substantially pure, injected vapor stream that comprises a light hydrocarbon,
such as propane.
In contrast, the systems and methods according to the present disclosure may
utilize a
hydrocarbon solvent mixture 35. The hydrocarbon solvent mixture 35 may include
a heavy
hydrocarbon fraction that comprises, consists of, or consists essentially of
hydrocarbons with
five or more carbon atoms ("C5+"). The heavy hydrocarbon fraction may comprise
greater
than 10 mole percent, greater than 20 mole percent, greater than 30 mole
percent, greater than
40 mole percent, greater than 50 mole percent, greater than 60 mole percent,
greater than 70
mole percent, or greater than 80 mole percent of hydrocarbon solvent mixture
35. The heavy
hydrocarbon fraction may comprise less than 99 mole percent, less than 95 mole
percent, less
than 90 mole percent, less than 80 mole percent, less than 70 mole percent,
less than 60 mole
percent, or less than 50 mole percent of hydrocarbon solvent mixture 35.
Suitable ranges may
include combinations of any upper and lower amount of mole percentage listed
above or any
number within the mole percentages listed above.
[0075] The heavy hydrocarbon fraction may include at least a first compound
that has five
or more carbon atoms and a second compound that has more carbon atoms than the
first
compound. The first compound and the second compound each may comprise at
least 10 mole
percent of hydrocarbon solvent mixture 35. For example, the first and/or
second compounds
may comprise at least 20 mole percent, at least 30 mole percent, at least 40
mole percent, at
least 50 mole percent, at least 60 mole percent, at least 70 mole percent, or
at least 80 mole
percent of hydrocarbon solvent mixture 35. Suitable ranges of the carbon atoms
or mole
percent of the first compound and the second compound may include combinations
of any
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upper and lower amount listed above or any number within or bounded by the
aforementioned
ranges.
[0076] The
heavy hydrocarbon fraction may comprise any suitable hydrocarbon molecules,
materials, and/or compounds. For example, the heavy hydrocarbon fraction may
comprise one
or more of alkanes, n-alkanes, branched alkanes, alkenes, n-alkenes, branched
alkenes, alkynes,
n-alkynes, branched alkynes, aromatic hydrocarbons, and/or cyclic
hydrocarbons.
[0077] The
hydrocarbon solvent mixture 35 may include a light hydrocarbon fraction that
may include hydrocarbons with fewer than five carbon atoms, such as
hydrocarbons with one
carbon atom, two carbon atoms, three carbon atoms, and/or four carbon atoms
("CI -C4"). The
light hydrocarbon fraction (when present) may, but is not required to,
comprise a minority
portion of the hydrocarbon solvent mixture. For example, the light hydrocarbon
fraction may
comprise at least 5 mole percent, at least 10 mole percent, at least 15 mole
percent, at least 20
mole percent, at least 30 mole percent, at least 40 mole percent, at least 50
mole percent, or at
least 60 mole percent of the hydrocarbon solvent mixture. The light
hydrocarbon fraction may
comprise less than 70 mole percent, less than 60 mole percent, less than 50
mole percent, less
than 40 mole percent, less than 30 mole percent, less than 20 mole percent,
less than 15 mole
percent, or less than 10 mole percent of the hydrocarbon solvent mixture.
Suitable ranges may
include combinations of any upper and lower amount of hydrocarbon fraction
ranges listed
above or any number within or bounded by the hydrocarbon fraction ranges
listed above.
[0078] The
hydrocarbon solvent mixture 35 may comprise any suitable number of
compounds and/or chemical species. For example, the hydrocarbon solvent
mixture may
include a third compound that may include more carbon atoms than the second
compound.
When the hydrocarbon solvent mixture includes the third compound, the third
compound may
comprise any suitable portion, or fraction, of the hydrocarbon solvent
mixture. The third
compound may comprise at least 20 mole percent, at least 30 mole percent, at
least 40 mole
percent, at least 50 mole percent, at least 60 mole percent, or at least 70
mole percent of the
hydrocarbon solvent mixture. The hydrocarbon solvent mixture 35 may include
alkanes, iso-
alkanes, naphthenic hydrocarbons, aromatic hydrocarbons, and/or olefin
hydrocarbons. In
general, normal alkanes may have a highest tendency of causing phase
separation of
asphaltenes, with a decreasing tendency for phase separation being observed
when moving
from iso-alkanes to naphthenic hydrocarbons to aromatic hydrocarbons.
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[0079] A hydrocarbon solvent mixture composition of hydrocarbon solvent
mixture 35
may be selected such that the vapor pressure of the hydrocarbon solvent
mixture at the stream
temperature is less than a threshold maximum pressure of the subterranean
reservoir. This may
prevent damage to the subterranean reservoir and/or escape of hydrocarbon
solvent mixture 35
from the subterranean reservoir. The threshold maximum pressure may include,
for example,
a characteristic pressure of the subterranean reservoir, such as a fracture
pressure of the
subterranean reservoir, a hydrostatic pressure within the subterranean
reservoir, a lithostatic
pressure within the subterranean reservoir, a gas cap pressure for a gas cap
that is present within
the subterranean reservoir, and/or an aquifer pressure for an aquifer that is
located above and/or
under the subterranean reservoir.
[0080] In preferred embodiments, the reservoir injection mixture 32 is
comprised of steam
50 and the hydrocarbon solvent mixture 35. The reservoir injection mixture 32
is injected into
subterranean reservoir 24 at a stream temperature. Steam 50 for use as part of
the reservoir
injection mixture 32 can be added from an external source, such as from a
boiler, or can be
produced, in full or in part, from within the surface facility 40 from waste
heat generated from
the overall recovery process, including waste heat generated form separating
the reservoir
heavy oil product stream 72 into the various component streams as shown in
Figure 1 as
described herein. At least a portion of the water product stream 46 was
optionally be used to
produce the steam required for the reservoir injection mixture 32.
[0081] The following paragraphs disclose preferred compositional and
operating ranges for
injecting a near-azeotropic mixture of steam 50 and the hydrocarbon solvent
mixture 35 which
is utilized as the reservoir injection mixture 32 in the processes as further
disclosed herein.
[0082] For practical purposes, the selection of the solvent molar
fraction and the operating
pressure constrains the temperature of the vapor phase assuming saturated
conditions.
[0083] In practice, as will become more apparent by the description below,
one may select
a hydrocarbon solvent mixture 35 (also referred to as "solvent" or "solvent
mixture" herein)
that has a favorable operating temperature and solvent molar fraction at the
azeotrope condition
when combined with steam 50. A favorable operating temperature is a
temperature that results
in economic production rates while delivering adequate or good thermal
efficiency. A
favorable solvent molar fraction is one that reduces the Solvent to Oil Ratio
(S010R) as
compared, for instance, with a heated VAPEX process.
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[0084] A physical phenomenon that increases the SolOR for heated VAPEX
and therefore
reduces the efficiency of the process is that when a heated solvent is
injected, it vaporizes all
the in-situ water, including a large fraction of the bound or irreducible
water, in the vicinity of
the injector.
[0085] As a result of this vaporization, at the boundary of the VAPEX
chamber, both water
and solvent condense together under conditions that are at or close to the
azeotrope. This is a
lower temperature than that of the injected heated solvent. Furthermore,
because the boundary
is relatively narrow, the idealistic benefits of a solvent-only process with
no flowing water are
not practically achieved.
100861 An important feature of the azeotrope pressure-temperature
conditions is that the
two fluids largely behave as a single fluid. That is, both fluids condense
together in the same
molar ratios of concentrations as they exist in the gas. Additionally, there
is no tendency for
either fluid to preferentially flash from the liquid state into the vapor
state (i.e. vaporize
additional in-situ water in the vicinity of the injector well). As such, the
combined fluids can
behave effectively as a single fluid with modified properties compared to
either single fluid.
[00871 Water is a very effective working fluid for transferring heat
whereas hydrocarbon
solvents tend to be relatively inefficient working fluids for that purpose.
Conversely,
hydrocarbon solvents are very effective viscosity reducing agents for heavy
oils whereas water
is practically immiscible. However, mixtures of hydrocarbons and water at the
azeotrope
.. behave largely as a single fluid with beneficial qualitative features of
both the water and the
hydrocarbon solvent mixture.
[0088] Without intending to be bound by theory, a near optimal injection
ratio of solvent
and steam vapor, where the fluid enters the reservoir, may be a ratio that is
at or close to the
azeotrope for the solvent-water mixture. Consider the case of injecting a
mixture of water and
hexane at 2.5 MPa. As shown in Figure 2, the molar fraction of solvent at the
azeotrope is
approximately 0.64 or 64% so that the water molar fraction is 0.36 or 36%. On
mass basis, this
converts to a 10.5% water fraction and on a volumetric basis this converts to
a 7% water
fraction. The heat of vaporization of hexane at the azeotrope temperature is
approximately 220
k.1/kg and that for water is about 2000 kJ/kg. The combined fluids have an
effective heat
capacity of about 410 kJ/kg. As a result, the mass of fluid required to
deliver the same heat to
the reservoir is approximately half and accordingly the operating solvent-to-
oil ratio would be
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expected to be about half.
[0089] If hexane vapor at 2.5 MPa is injected into the reservoir it will
be at a temperature
of 220 C (see Figure 2). As the hot hydrocarbon vapor enters the reservoir and
enters pore
spaces with liquid water, the water will vaporize and a fraction of the
solvent will condense.
The temperature will also decline until the water-hydrocarbon system in vapor
phase finds an
equilibrium point near the azeotrope. At that point, any additional
condensation will result in
the water and solvent condensing with the mole fraction ratio of the
azeotrope. The
solvent-steam mixture that progresses to the boundary of the vapor chamber
will be a mixture
at or close to the azeotrope. This phenomenon has several of important
implications:
[0090] 1. A significant volume of reservoir rock will be increased in
temperature to as
much as 220 C which is an additional heat sink compared to injection at the
azeotrope
temperature of 182 C.
[0091] 2. Due to the hotter injection fluids and conductive heating in
the vicinity of the
producer, produced fluids will be at a higher temperature. Hence more heat
will be produced
back from the reservoir which is less thermally efficient.
[0092] 3. Vaporized solvent is condensing in the reservoir in order to
vaporize water which
is then carrying the heat to the boundary of the steam chamber, which is not
effectively using
the benefits of the solvent. That is, as described above, hydrocarbon solvents
tend to be
relatively inefficient working fluids for transferring heat but are very
effective viscosity
reducing agents.
[0093] 4. A region will develop around the injector which is nearly
completely water free
(sometimes called a desiccation zone). It is possible that this could be
advantageous in some
circumstances. However it could also be a disadvantage due to factors such as
salt or scale
deposition and pore plugging, fines movement causing pore plugging and a shift
from a water
wet system to an oil wet system resulting in less favorable residual oil
saturations and relative
permeabilities.
[0094] Practical implications of using near-azeotropic injection are
partly illustrated by the
results of some analyses that are provided in Tables 1 and 2. Table 1 shows
the azeotropic
temperatures and molar concentrations for pentane, hexane and heptane at 1 MPa
and 2.5 MPa
pressures. Table 1 also provides mass fractions, standard volumetric fractions
and enthalpies
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. r
for steam and solvent at their respective, ideal partial pressures for the
azeotropic temperature.
It can be seen from Table 1 that the azeotrope molar concentration of steam
increases
significantly from lighter to heavier solvents. However, for a given solvent
there is limited
variation with pressure. It can also be seen from Table 1 that the heat of
vaporization for the
combined fluids increases much more substantially for heavier solvents at the
azeotrope than
it does for the lighter solvents. Table 2 lists an assumed injected solvent-to-
oil ratio (SciOR)
for each of the cases shown in Table 1. For illustrative purposes, the assumed
SoiOR increases
with solvent type and pressure proportionally to the difference between the
azeotrope operating
temperature and an assumed initial reservoir temperature of 7 C. The fifth and
sixth columns
of the Table 2 show the equivalent combined steam to oil ratio (SOR) and SolOR
when
operating with azeotropic injection. In all cases, the required solvent
recirculation is
significantly reduced. For pentane, it is estimated to be about a 23%
reduction at 1 MPa. The
benefit is predicted to increase with pressure and with the use of heavier
solvents. The required
solvent recycling is predicted to be reduced by 50% or more for heavier
solvents.
Table 1. Properties for steam-solvent
Design Parameters Azeotrope Properties (Approximate)
Steam-Solvent Ratios Thermal Properties
Steam Solvent Steam Solvent Steam Solvent Steam Heat
Solvent Heat Combined
Solvent Pressure Temperature Molar Molar Mass Mass
Volume Volume of of Fluid Heat of
Fraction Fraction Fraction Fraction Fraction Fraction Vaporization
Vaporization Vaporization
Mpa deg. C. k.kkg Ir.Fkg klicg
Pentane I 116 0.16 0.84 0.045 , 0.955 0.029 0.971
2213 319 405
Hexane 1 140.5 0.34 0.66 0.097 0.903 0.066 0.934
2142 270 452
Heptane 1 155.7 0.54 0.46 0.174 0.826 0.125 0.875
2095 226 551
Pentane 15 157.7 0.20 0.80 0.059 0.941 0.038 0.962
2089 208 318
Hexane 2.5 182 , 0.36 0.64 0.105 0.895 0.071
0.929 2006 220 408
Heptmie 25 1969. 0.54 0.46 0.174 0.826 0.125 0.875
1951 210 513
Table 2. Representative Solvent-only and Isotropic Steam-Solvent Ratios
Solvent Pressure Temperature Solvent-only
Azeotrope Combined SoiOR Reduction
Mpa deg. C. SõIOR Steam SOP. Solvent S,,IOR
%
Pentane I 116 8.8 0.20 6.8 23
Hexane I 140.5 12.1 0.49 7.0 42
Heptane I 155.7 15.6 0.86 6.0 61
Pentane 2,5 157.7 18.6 0.46 11.9 36
Hexane 2.5 182 19.4 0.78 10.1 48
Heptane 2.5 196.9 21.4 1.18 8.3 61
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Simulation Results
[0095] The
concept described herein is examined by a numerical simulation in a typical
Athabasca reservoir. Figure 3 shows the reservoir properties map for single
component solvent
H-VAPEX (n-05 or normal-pentane) and Azeotropic H-VAPEX ("AH-VAPEX") at the
same
operating pressure condition. As seen in the temperature map, the average
temperature in the
depleted zone for AH-VAPEX with no near wellbore heating is lower than the H-
VAPEX case.
It is also noted from the water saturation map that in AH-Vapex, the co-
injected steam at the
azeotropic concentrations inhibited the vaporization of the initial in-situ
water and minimized
solvent condensation to provide the required energy for water vaporization.
The improvement
in SedOR for this case is shown in Figure 4. Figure 4 also shows the
improvement in the &DIOR
for AH-VAPEX in azeotropic steam-nC7 (steam-normal-heptane) system. As
described above,
the azeotropic systems for heavier solvents results in a higher energy content
in the injected
azeotropic fluid compared to lighter solvents and therefore results in a
higher reduction in
SolOR, as is shown Table 1 and Table 2 and in Figure 4.
[0096] The vaporized in-situ water in H-VAPEX in the depleted zone is
replaced with
hydrocarbon liquid phase which is mainly condensed liquid solvent. Prevention
(or limitation)
of in-situ water vaporization in the AH-VAPEX results in reduction of liquid
hydrocarbon
phase in the depleted chamber and therefore reduction in solvent retention in
the depleted
reservoir. This is seen in the liquid phase saturation map in Figure 3 as a
reduced residual liquid
phase saturation region within depleted chamber in AH-VAPEX compared to H-
VAPEX. The
reduction in solvent retention in reservoir is reflected in Figure 5 in terms
of an increase in
produced oil-to-retained solvent ratio (PBRSR). It is noted that nC7 AH-VAPEX
has a higher
increase in PBRSR compared to the nC5 AH-VAPEX. The oil recovery rates in the
azeotropic
H-VAPEX and H-VAPEX is generally similar as shown in Figure 6.
[0097] For field applications, the commercially available solvents are
generally a mixture
of hydrocarbon compounds rather than a pure single compound. Commercial gas
condensate,
diluents, and naphtha are among the used solvents. The phase behavior of these
multicomponent solvents with steam is more complicated than the single
compound solvents.
However, their phase behavior when mixed with steam can be considered as
superposition of
individual pure compounds behavior. These systems exhibit a semi-azeotropic
behavior with a
minimum boiling characteristic similar to single compound solvents. Figure 7
shows the semi-
azeotropic behavior of steam-diluent system. The minimum dew point temperature
in this
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system is the co-condensation point of steam-solvent components at a semi-
azeotropic water
concentration similar to azeotropic point in a single component solvent-steam
system. Figures
8 and 9 show the enhancement effects in SolOR and PBRSR of semi-azeotropic
steam-diluent
AH-VAPEX compared to diluent H-VAPEX. Figures 8 and 9 also compare the SOIOR
and
PBRSR improvement in a high initial water saturation reservoir (lean
reservoir, So=0.61),
compared to an Athabasca reservoir with typical initial water saturation
(So=0.87). Oil
saturation of "So" is a fraction of oil volume based on pore volume.
[0098]
Potential advantages in terms of efficiency of near-azeotropic injection in
AH-VAPEX relative to heated VAPEX include:
1. The average temperatures in the vapor chamber are reduced while the
temperature at the chamber boundary remains near the azeotrope temperature.
2. The temperatures at the top of the steam chamber will also be reduced
resulting
in less heat loss to the overburden.
3. There is virtually no thermodynamic tendency to vaporize water (mobile,
immobile or bound) within the vapor chamber. This eliminates (or reduces) the
complexities
and potential problems associated with a dry (or desiccation) zone.
4. Preventing in-situ water (mobile, immobile or bound) vaporization in the
near-
azeotropic injection results in a reduction of the liquid hydrocarbon phase in
the depleted
chamber, reduction in solvent concentration in the vapor phase in the depleted
chamber, and
therefore a reduction in solvent retention in reservoir.
5. Since water is a much more effective thermal working fluid than hydrocarbon
solvents, the combined fluids have a grcater average working enthalpy
associated with the
condensation of the vapor.
6. Oil rates from the process will remain largely unchanged since in either
process
water is condensing at the boundary with the solvent at similar water to
solvent ratios.
7. Heat loss from the wellbore can result in significant condensation of
fluids. An
additional volume or molar concentration of water can be added to the injected
stream at
surface such that water preferentially condenses in the wellbore and injection
at the sand face
is then near the azeotrope.
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8. It may also be advantageous to inject vapor at the sand face with a water
concentration marginally above the azeotrope concentration so that, for
example, in later life,
primarily water condenses at the top of the reservoir. In particular, solvent
that condenses on
the top of the steam chamber and drains down is not as effective as solvent
that condenses on
the oil interface. If one injects above the steam azeotrope concentration, it
will be water that
condenses first at the top of the steam chamber. As a result, the optimal
molar fraction of steam
may start at or near the azeotrope and increase with time. There will likely
be a reduction in
the volume of vapor being injected into the reservoir which may allow for
smaller wellbore
sizes and tubulars.
[0099] Since thermal separation will be required in order to recycle
solvent, process
facilities may be designed to flash water at a desired concentration.
[00100] Overall, advantages of near-azeotropic injection may include
reductions in the
solvent-to-oil ratio (S010R) relative to solvent-only heated VAPEX, a
potentially broader
applicability to higher initial water saturation resources, a reduction in
solvent storage, and an
improvement in the produced oil-to-retained solvent ratio.
[00101] The hydrocarbon solvent mixture (or "solvent") may be a fluid of a
lower viscosity
and lower density than those of the viscous oil being recovered. Its viscosity
may, for example,
be 0.2 to 5 cP (centipoise) at room temperature and at a pressure high enough
to make it liquid.
Its density may be, for example, 450 to 950 kg/m3 at 15 C and at a pressure
high enough to
make it liquid. The mixture or the blend of solvent and viscous oil may have a
viscosity and a
density that is in between those of the solvent and the viscous oil. The
solvent may or may not
precipitate asphaltenes if its concentration exceeds a critical concentration.
[00102] The hydrocarbon solvent mixture may be a single hydrocarbon compound
or a
mixture of hydrocarbon compounds having a number of carbon atoms in the range
of CI to
Cm+. The hydrocarbon solvent mixture may have at least one hydrocarbon in the
range of C3
to Cu and this at least one hydrocarbon may comprise at least 50 wt. % of the
solvent. The
mixture may have aliphatic, naphthenic, aromatic, and/or olefinic fractions.
[00103] The hydrocarbon solvent mixture may comprise at least at least 50 wt.
% of one or
more C3-C12 hydrocarbons, at least 50 wt. % of one or more Ca-CI
hydrocarbons, at least 50
wt. % of one or more C5-C7 hydrocarbons. The hydrocarbon solvent mixture may
comprise a
natural gas condensate or a crude oil refinery naphtha.
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[00104] The hydrocarbon solvent mixture may comprise alkanes, iso-alkanes,
naphthenic
hydrocarbons, aromatic hydrocarbons, and/or olefin hydrocarbons. In general,
normal alkanes
may have a highest tendency of causing phase separation of asphaltenes, with a
decreasing
tendency for phase separation being observed when moving from iso-alkanes to
naphthenic
hydrocarbons to aromatic hydrocarbons.
[00105] Upon selecting an operating temperature range (for instance 60-140 C),
a solvent
may be selected that has a vapor pressure that does not exceed a selected
maximum pressure.
[00106] The hydrocarbon solvent mixture may be chosen to be compatible with
the desired
reservoir operating pressure such that economics of the process will be
optimized through a
combination maximizing the producing oil rate, minimizing the injected solvent
to oil ratio,
minimizing the injected steam to oil ratio, maximizing the produced oil-to-
retained solvent
ratio, and selecting lower cost-of-supply solvents.
[00107] The steam may have a quality (defined as the wt. % of total steam
present as steam
vapour, and the remainder as liquid) of at least 5%, or 10-100%. The steam may
be present in
a near-azeotropic injection stream in an amount of 2-85 vol. % and solvent may
be present in
an amount of 15-98 vol.%, both calculated at standard temperature and pressure
(SIP) and in
cold liquid equivalents. The volume percentage range must be determined for
each solvent at
given pressure. By way of example, the cold liquid equivalent volume
percentage range for C4
is 2-7 vol% and for C12 is 80-85 vol%.
1001081 The solvent molar fraction may be decreased over time.
[00109] The steam and solvent may be injected with other components, such as:
diesel,
aromatic light catalytic gas oil, or another solvent, to provide flow
assurance, or CO2, natural
gas, C3+ hydrocarbons, ketones, or alcohols.
[00110] The process may further comprise separating and reusing the solvent
and water in
a separation, purification, revaporization and reinjection facility.
[00111] The gravity drainage process may involve directional drilling to place
two
horizontal wells in the viscous oil reservoir ¨ a lower well and an upper well
positioned above
it. The solvent and steam may be injected into the upper well to dilute and
reduce the viscosity
of the viscous oil. The viscous oil, solvent, and condensed steam will then
drain downward
through the reservoir under the action of gravity and flow into the lower
production well,
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whereby these fluids can be pumped to the surface. At the surface of the well,
all or a fraction
of the solvent or a mixture of reduced-viscosity hydrocarbons may be separated
from the
produced fluids and reused as the solvent for injection with the steam. All or
a fraction of the
solvent or reduced-viscosity hydrocarbons may also remain mixed with the oil
to aid in
transport to a refinery or an upgrader.
[00112] Light hydrocarbon gases may also be separated from the produced
fluids and may
include hydrocarbons and/or carbon compounds with four or fewer carbon atoms,
such as
methane, ethane, propane, and/or butane. Light hydrocarbon gases may be used
upstream in
the process, for instance, as fuel to heat the solvent and steam prior to
injection.
[00113] The operating pressure for the process may be informed by many
external factors
such as needing to be close to the pressure of nearby water zones, gas zones
or other operations
such that the injected fluids do not migrate away from the production well and
unwanted fluids
do not migrate to the production well. Additionally, the potential for
formation fracturing may
limit the maximum pressure. As such, the choice of solvent may be driven by
the acceptable
range of operating pressures.
100114] A threshold maximum pressure also may be related to and/or based upon
the
characteristic pressure of the subterranean reservoir. The reservoir operating
pressure may be
5-95% of a fracture pressure of the reservoir, or 0.2 to 4 MPa, or 1 to 2.5
MPa.
[00115] The injection temperature of the hydrocarbon solvent mixture and
steam, when it is
injected into the injection well, may be affected by the selection of the
molar concentration of
the steam and the solvent once the optimal solvent has been selected. The
thermodynamic phase
behavior will dictate that injection temperature is the saturation temperature
corresponding to
the molar concentration of the steam and the solvent in absence of any degrees
of superheat.
The molar concentration of the steam will most often be higher than the
azeotropic
concentration in order to most efficiently manage heat losses.
Correspondingly, the
temperature will be higher than the azeotropic temperature as well. The
injection temperature
of the hydrocarbon solvent mixture and steam may be 30-250 C or 80-150 C.
Conversely,
the actual subterranean reservoir operating temperature may be 30-250 C or 80-
150 C.
[00116] The heat of vaporization of the hydrocarbon solvents is much smaller
than steam.
Therefore, one may add excess steam to an azeotropic mixture of hydrocarbon
vapor and steam.
The thermodynamic phase behavior dictates that the excess steam will condense
first to provide
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the required energy for heat losses. By way of example, a mixture of steam and
hydrocarbon
vapor may be prepared at a central processing facility with a solvent molar
fraction (X1) less
than the azeotropic vapor solvent molar fraction (Xaz) and a temperature (T1)
greater than the
azeotropic temperature (Taz). As the mixture flows through the pipelines
toward the wellhead,
some of excess steam will condense due to heat losses. At the wellhead, the
vapor mixture may
have a higher solvent molar fraction (X2, i.e. X2>X1>Xaz) and a lower
temperature (T2, i.e.
T2<T1). At the wellhead, preferably X2>Xaz and T2>Taz. As the mixture flows
down the
well, some of the excess steam will again condense due to heat losses. At the
sand face, the
vapor mixture may have a solvent molar fraction (X3) where X3>X2 and a
temperature (T3)
where T3<T2. Preferably, at the sand face X3>Xaz and 13>Taz. In this way, one
can inject the
mixture at the sand face with some extra steam as compared to an azeotropic
mixture to provide
the energy required to account for heat losses to the overburden. Heaters can
also be utilized
on the surface or downhole to add some degree of superheat to the solvent and
vapor mixture
in order to ensure single phase flow. Examples are surface heaters and
downhole electrical
heaters. Therefore, the solvent and steam vapor mixture may be injected at 1-
50 C or 1-20 C
of superheat, measured at the sand face, with respect to the saturation
temperature of the solvent
molar fraction at the reservoir operating pressure.
[00117] As described above, near-azeotropic injection of solvent and steam
means using a
solvent molar fraction of 70-100% of the azeotropic solvent molar fraction.
Simulation results
have shown than the total injected energy per volume of bitumen produced and
the bitumen
production rate are not be considerably affected by varying the composition of
the injected
fluid in this range. As an example, for C5 (pentane) one may inject with a
solvent molar fraction
of 0.62-0.88, and for C9 (nonane) one may inject with a solvent molar fraction
of 0.13-0.18,
both at a pressure of 500 lcPa. These compositions translate to different dew
point temperature
ranges for each solvent, and as illustrated in Figure 10, namely, 87-119 C for
C5, and 145-
147 C for C9. In general, as pressure increases the temperature range
corresponding to 70% to
100% (or other ranges) of the azeotropic solvent molar fraction becomes
narrower.
[00118] Separation of the produced fluid may be effected in any suitable
separation system
or structure, such as a single stage separation vessel, a multistage
distillation assembly, a liquid-
liquid separation or extraction assembly and/or any suitable gas-liquid
separation, or extraction
assembly.
[00119] Purification of the solvent may be effected in any suitable system or
structure, such
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as any suitable liquid-liquid separation or extraction assembly, any suitable
gas-liquid
separation or extraction assembly, any suitable gas-gas separation or
extraction assembly, a
single stage separation vessel, and/or any suitable multistage distillation
assembly.
[00120] Vaporization of the solvent may be effected by any suitable system or
structure
above ground or downhole.
[00121] The injection well may be spaced apart from the production well. The
production
well may extend at least partially below the injection well, may extend at
least partially
vertically below the injection well, and/or may define a greater distance (or
average distance)
from the surface when compared to the injection well. At least a portion of
the production well
may be parallel to, or at least substantially parallel to, a corresponding
portion of the injection
well. At least a portion of the injection well, and/or of the production well,
may include a
horizontal, or at least substantially horizontal, portion.
[00122] The process may include preheating or providing thermal energy to at
least a portion
of the subterranean reservoir in any suitable manner. The preheating may
include electrically
preheating the subterranean reservoir, chemically preheating the subterranean
reservoir, and/or
injecting a preheating steam stream into the subterranean reservoir. The
preheating may include
preheating any suitable portion of the subterranean reservoir, such as a
portion of the
subterranean reservoir that is proximal to the injection well, a portion of
the subterranean
reservoir that is proximal to the production well, and/or a portion of the
subterranean reservoir
that defines a vapor chamber that receives the solvent and steam.
1001231 Heating the solvent may include directly heating the solvent in a
surface region or
using the co-injection with the steam.
[00124] Condensing the solvent and steam within the subterranean reservoir may
include
condensing any suitable portion of the solvent and steam to release a latent
heat of condensation
of the solvent and steam, heat the subterranean reservoir, heat the viscous
oil, and/or generate
the reduced-viscosity hydrocarbons within the subterranean reservoir. The
condensing may
include condensing a majority, at least 50 wt. %, at least 60 wt. %, at least
70 wt. %, at least 80
wt. %, at least 90 wt. %, at least 95 wt. %, at least 99 wt. %, or
substantially all of the solvent
and steam within the subterranean reservoir. The condensing may include
regulating a
temperature within the subterranean reservoir to facilitate, or permit, the
condensing.
[00125] Producing the reduced-viscosity hydrocarbons may include producing the
reduced-
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viscosity hydrocarbons via any suitable production well, which may extend
within the
subterranean reservoir and/or may be spaced apart from the injection well.
This may include
flowing the reduced-viscosity hydrocarbons from the subterranean reservoir,
through the
production well, and to, proximal to, and/or toward the surface region.
[00126] The producing may include producing asphaltenes. The asphaltenes may
be present
within the subterranean reservoir and/or within the viscous oil. The
asphaltenes may be
produced as a portion of the reduced-viscosity hydrocarbons (and/or the
reduced-viscosity
hydrocarbons may include, or comprise, asphaltenes). The injecting may include
injecting into
a stimulated region of the subterranean reservoir that includes asphaltenes,
and the producing
may include producing at least a threshold fraction of the asphaltenes from
the stimulated
region. This may include producing at least 10 wt. %, at least 20 wt. %, at
least 30 wt. %, at
least 40 wt. %, at least 50 wt. %, at least 60 wt. %, at least 70 wt. %, at
least 80 wt. %, or at
least 90 wt. Ã1/0 of the asphaltenes that are, or were, present within the
stimulated region prior to
the injecting. The fractions of the asphaltenes that are produced and left in
the reservoir is a
function of the operating temperature, pressure and the choice of solvents.
The determination
of these parameters may be influenced by the fraction of asphaltenes that is
produced and
associated value of the produced hydrocarbons.
[00127] Recycling the solvent may include recycling the solvent in any
suitable manner.
The recycling may include separating at least a separated portion of the
solvent from the
reduced-viscosity hydrocarbon mixture and/or from the reduced-viscosity
hydrocarbons. The
recycling also may include utilizing at least a recycled portion of the
solvent as, or as a portion
of, the hydrocarbon solvent mixture and/or returning the recycled portion of
the condensate to
the subterranean reservoir via the injection well. The recycling may include
purifying the
recycled portion of the solvent prior to utilizing the recycled portion of the
solvent and/or prior
to returning the recycled portion of the solvent to the subterranean
reservoir.
[00128] The properties of the azeotropic mixture which condenses at the
boundary of the
vapour chamber are strongly influenced by the lightest hydrocarbons present in
the injected
solvent so the recycling process may have facilities designed to specifically
remove the lightest
components.
[00129] Pressures, such as the previously discussed pressures, may be measured
and/or
determined in any suitable manner. As examples, pressure may be measured with
a downhole
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pressure sensor, calculated from any suitable property and/or characteristic
of the subterranean
=
reservoir, and/or estimated, such as via modeling the subterranean reservoir.
The threshold
maximum pressure may be selected to correspond in any suitable or desired
manner to one or
more of these measured or calculated characteristic pressures. For example,
the disclosed
threshold maximum pressure may be selected to be, to be greater than, to be
less than, to be
within a selected range of, to be a selected percentage of, to be within a
selected constant of,
etc. one or more of these measured or calculated characteristic pressures. The
threshold
maximum pressure may be a user-selected, or operator-selected, value that does
not directly
correspond to a measured or calculated pressure.
[00130] The threshold maximum pressure also may be related to and/or based
upon the
characteristic pressure of the subterranean reservoir. The threshold maximum
pressure may be
less than 95%, less than 90%, less than 85%, less than 80%, less than 75%,
less than 70%, less
than 65%, less than 60%, less than 55%, or less than 50% of the characteristic
pressure for the
subterranean reservoir. The threshold maximum pressure may be at least 20%, at
least 25%,
at least 30%, at least 35%, at least 40%, at least 45%, at least 50%, at least
55%, at least 60%,
at least 65%, at least 70%, at least 75%, or at least 80% of the
characteristic pressure for the
subterranean reservoir. Suitable ranges may include combinations of any upper
and lower
amount of percentage ranges listed above or any number within or bounded by
the percentage
ranges listed above.
1001311 Examples of vapor pressures for hydrocarbon solvent mixtures 32
include vapor
pressures that are greater than a lower threshold pressure of at least 0.2
megapascals (MPa), at
least 0.3 MPa, at least 0.4 MPa, at least 0.5 MPa, at least 0.6 MPa, at least
0.7 MPa, at least 0.8
MPa, at least 0.9 MPa, at least 1 MPa, at least 1.1 MPa, at least 1.2 MPa, at
least 1.3 MPa, at
least 1.4 MPa, at least 1.5 MPa, at least 1.6 MPa, at least 1.7 MPa, at least
1.8 MPa, at least 1.9
MPa, at least 2 MPa, at least 2.1 MPa, at least 2.2 MPa, at least 2.3 MPa, at
least 2.4 MPa,
and/or at least 2.5 MPa. The vapor pressure for the hydrocarbon solvent
mixture may be less
than an upper threshold pressure that is less than 3 MPa, less than 2.9 MPa,
less than 2.8 MPa,
less than 2.7 MPa, less than 2.6 MPa, less than 2.5 MPa, less than 2.4 MPa,
less than 2.3 MPa,
less than 2.2 MPa, less than 2.1 MPa, less than 2 MPa, less than 1.9 MPa, less
than 1.8 MPa,
less than 1.7 MPa, less than 1.6 MPa, less than 1.5 MPa, less than 1.4 MPa,
less than 1.3 MPa,
less than 1.2 MPa, less than 1.1 MPa, less than 1 MPa, less than 0.9 MPa, less
than 0.8 MPa,
less than 0.7 MPa, less than 0.6 MPa, less than 0.5 MPa, less than 0.4 MPa,
and/or less than
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0.3 MPa. Suitable ranges may include combinations of any upper and lower
amount of pressure
ranges listed above or any number within or bounded by the pressure ranges
listed above.
1001321 Examples of stream temperatures of hydrocarbon solvent mixture 32 when
it is
injected into injection well 30 include stream temperatures of at least 30
degrees ( ) Celsius
(C), at least 35 C, at least 40 C, at least 45 C, at least 50 C, at least
55 C, at least 60 C, at
least 65 C, at least 70 'V, at least 75 C, at least 80 C, at least 85 C,
at least 90 C, at least 95
C, at least 100 C, at least 105 C, at least 110 'V, at least 115 C, at
least 120 C, at least 125
C, at least 130 'V, at least 135 'V, at least 140 C, at least 145 C, at
least 150 'V, at least 155
C, at least 160 C, at least 165 C, at least 170 C, at least 175 C, at
least 180 C, at least 185
C, at least 190 C, at least 195 C, at least 200 C, at least 205 C, and/or
at least 210 'C.
Additionally or alternatively, the stream temperature also may be less than
250 C, less than
240 C, less than 230 C, less than 220 C, less than 210 C, less than 200
C, less than 190 C,
less than 180 'V, less than 170 C, less than 160 C, less than 150 C, less
than 140 C, less than
130 C, less than 120 'V, less than 110 C, less than 100 C, less than 90 C,
less than 80 C,
less than 70 C, less than 60 C, less than 50 'V, and/or less than 40 C.
Suitable ranges may
include combinations of any upper and lower amount of temperature ranges
listed above or any
number within or bounded by the temperature ranges listed above.
1001331 Injection well 30 may include any suitable structure that may form a
fluid conduit
to convey hydrocarbon solvent mixture 32 to, or into, subterranean reservoir
24 and/or to, or
into, solvent extraction chamber 60. Production well 70 may include any
suitable structure that
may form a fluid conduit to convey the reservoir heavy oil product stream 72
from subterranean
reservoir 24 to, toward, and/or proximal, surface region 20. As an example,
and as illustrated
in Fig. 1, injection well 30 may be spaced apart from production well 70.
Production well 70
may extend at least partially below injection well 30, may extend at least
partially vertically
below injection well 30, and/or may defme a greater distance (or average
distance) from surface
region 20 when compared to injection well 30. At least a portion of production
well 70 may
be parallel to, or at least substantially parallel to, a corresponding portion
of injection well 30.
At least a portion of injection well 30, and/or of production well 70, may
include a horizontal,
or at least substantially horizontal, portion.
[00134] Bituminous hydrocarbon deposit 25 may include and/or be any suitable
subterranean hydrocarbon deposit that may include bitumen and/or asphaltenes.
Bituminous
hydrocarbon deposit 25 may be referred to as a viscous hydrocarbon deposit 25,
a bitumen
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deposit 25, an oil sands deposit 25, and/or an asphaltene-containing deposit
25. An example
of a bituminous hydrocarbon deposit 25 that may be included in and/or utilized
with the
systems and methods according to the present disclosure may include the
Athabasca bitumen
deposit in Alberta, Canada.
[00135] Bituminous hydrocarbon deposit 25 may include a wide range of
hydrocarbon
molecules that may possess a correspondingly wide range of molecular carbon
contents,
molecular weights, viscosities, densities, chemical functionalities, and/or
solvent solubilities.
Bituminous hydrocarbon deposit 25 may include hydrocarbon molecules with
eleven (i.e., CI i)
or more carbon atoms. The composition of the bituminous hydrocarbon deposit
may be
to characterized into two different fractions. The first fraction, which
may be referred to as the
light fraction, the light end, the light end fraction, and/or the light end
components, may include
hydrocarbon molecules with eleven to thirty carbon atoms (i.e., Ci i-C30). The
second fraction,
which may be referred to as the heavy fraction, the heavy end, the heavy end
fraction, and/or
the heavy end components, may include hydrocarbon molecules with greater than
thirty carbon
atoms (i.e., C30+). The first fraction and the second fraction often may
separate into two
different liquid phases (i.e., a light liquid phase and a heavy liquid phase)
in the reservoir heavy
oil product stream 72 that is formed from bituminous hydrocarbon deposits 25.
Asphaltenes
are heavy end components and may be present in the heavy liquid phase;
however, under
certain conditions, a portion of the asphaltenes may precipitate from the
heavy liquid phase,
forming a separate solid, or semi-solid, phase.
[00136] The portion of the asphaltenes that precipitate from the heavy liquid
phase and/or a
fraction of the heavy liquid phase that may be produced with the reservoir
heavy oil product
stream 72 may depend upon the reservoir injection mixture composition. The
reservoir
injection mixture composition may be regulated to regulate the precipitation
of the asphaltenes
and/or the fraction of the heavy liquid phase that is produced with the
reservoir heavy oil
product stream.
[00137] Bituminous hydrocarbon deposits 25 that may be included in and/or
utilized with
the systems and methods according to the present disclosure may include any
suitable portion,
proportion, or fraction of the light end components, the heavy end components,
and/or
asphaltenes. Prior to being produced from the subterranean reservoir, such as
by utilizing the
systems and methods that are disclosed in the present disclosure, the light
end components, the
heavy end components, and the asphaltenes may form a (heterogeneous and/or
homogeneous)
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multicomponent mixture that defines bituminous hydrocarbon deposit 25. The
light end
components, the heavy end components, and the asphaltenes may be (at least
substantially)
indistinguishable within bituminous hydrocarbon deposit 25. During and/or
subsequent to
being combined with reservoir injection mixture 32, the light end components,
the heavy end
components, and/or the asphaltenes may separate from one another and/or may
become
separate, or distinct, phases within the subterranean reservoir and/or within
the product
hydrocarbon stream.
[00138] The light end components may comprise at least 10 weight percent, at
least 15
weight percent, at least 20 weight percent, at least 25 weight percent, or at
least 30 weight
percent of the bituminous hydrocarbon deposit. The light end components also
may comprise
less than 50 weight percent, less than 45 weight percent, less than 40 weight
percent, less than
35 weight percent, or less than 30 weight percent of the bituminous
hydrocarbon deposit.
Suitable ranges may include combinations of any upper and lower amount of
weight percent
ranges listed above or any number within or bounded by the weight percent
ranges listed above.
[00139] The heavy end components may comprise at least 50 weight percent, at
least 55
weight percent, at least 60 weight percent, at least 65 weight percent, or at
least 70 weight
percent of the bituminous hydrocarbon deposit. The heavy end components also
may comprise
less than 90 weight percent, less than 85 weight percent, less than 80 weight
percent, less than
75 weight percent, or less than 70 weight percent of the bituminous
hydrocarbon deposit.
Suitable ranges may include combinations of any upper and lower amount of
weight percent
ranges listed above or any number within or bounded by the weight percent
ranges listed above.
[00140] The asphaltenes may comprise at least 1 weight percent, at least 2.5
weight percent,
at least 5 weight percent, at least 7.5 weight percent, at least 10 weight
percent, at least 12
weight percent, at least 14 weight percent, at least 16 weight percent, or at
least 18 weight
percent of the bituminous hydrocarbon deposit. The asphaltenes also may
comprise less than
24 weight percent, less than 22 weight percent, less than 20 weight percent,
or less than 18
weight percent of the bituminous hydrocarbon deposit. In preferred
embodiments, the target
asphaltene content or actual asphaltene content of the produced reservoir
heavy oil product
stream is from 1 to 30 weight percent. Suitable ranges may include
combinations of any upper
and lower amount of weight percent ranges listed above or any number within or
bounded by
the weight percent ranges listed above.
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[00141] The disclosed systems and methods may utilize the variable solubility
of
asphaltenes n different reservoir injection mixtures 32 to control, regulate,
and/or vary the
asphaltene content of reservoir heavy oil product stream 72 and/or to control,
regulate, and/or
vary a proportion of the asphaltenes that are present within bituminous
hydrocarbon deposit 25
that is produced with the reservoir heavy oil product stream 72.
[00142] Surface facility 40 may receive the reservoir heavy oil product stream
72 from
production well 70. The reservoir heavy oil product stream 72 may include
hydrocarbon
solvent mixture, condensate, and/or reduced-viscosity hydrocarbons, including
bitumen,
gaseous hydrocarbons, and/or asphaltenes. The reservoir heavy oil product
stream 72 also may
include water.
[00143] Referring more generally to Fig. 1, the systems and methods according
to the
present disclosure may include controlling, regulating, and/or varying a
reservoir injection
mixture 32 composition that is injected into injection well 30.
[00144] For example, the reservoir injection mixture composition may be varied
to maintain
at least a threshold asphaltene content within the reservoir heavy oil product
stream 72. The
hydrocarbon solvent mixture composition may be varied to maintain the
asphaltene content
within the reservoir heavy oil product stream 72 at, or near, a target
asphaltene content. The
target asphaltene content may be different from (or greater than) the
threshold asphaltene
content.
[00145] The composition of the reservoir injection mixture 32 may be varied
based upon a
desired stream temperature at which the reservoir injection mixture is
injected into injection
well 30 and/or based upon a desired temperature within solvent extraction
chamber 60. The
desired temperature may impact the viscosity of bituminous hydrocarbon deposit
25 and/or the
solubility of bituminous hydrocarbon deposit 25 within the reservoir injection
mixture 32.
[001461 The reservoir injection mixture composition may be varied based upon a
desired
pressure at which the reservoir injection mixture is injected into injection
well 30 and/or based
upon a desired pressure within solvent extraction chamber 60. The desired
pressure may
impact the average saturation temperature of injected solvent and consequently
the viscosity of
bituminous hydrocarbon deposit 25, the solubility of bituminous hydrocarbon
deposit 25 within
the reservoir injection mixture 32, and/or a production rate of the reservoir
heavy oil product
stream 72. The composition of the reservoir injection mixture composition,
including the
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composition of the hydrocarbon solvent mixture 35 may be varied in any
suitable manner. The
hydrocarbon solvent mixture 35 may include a plurality of hydrocarbon
molecules that defines,
or has, an average molecular carbon content; the hydrocarbon solvent mixture
composition
may be varied by varying the average molecular carbon content. The phrase
"average
molecular carbon content" may refer to an average number of carbon atoms that
may be present
in hydrocarbon molecules that comprise hydrocarbon solvent mixture 35.
[00147] The hydrocarbon solvent mixture 35 might comprise 25 mole percent
propane
(which includes three carbon atoms), 25 mole percent butane (which includes
four carbon
atoms), 25 mole percent pentane (which includes five carbon atoms), and 25
mole percent
1() hexane (which includes six carbon atoms). For such a hydrocarbon solvent
mixture 35, the
average molecular carbon content would be (0.25*3+0.25*4+0.25*5+0.25*6), which
yields an
average molecular carbon content of 4.5. The hydrocarbon solvent mixture 35
might comprise
50 mole percent propane and 50 mole percent pentane. For such a hydrocarbon
solvent mixture
35, the average molecular carbon content would be (0.5*3+0.5*5), which yields
an average
molecular carbon content of 4Ø
[00148] The systems and methods according to the present disclosure are
described in the
context of the average molecular carbon content of hydrocarbon solvent mixture
35. However,
it is to be understood that changes in the average molecular carbon content
may produce a
proportionate change in an average molecular weight of hydrocarbon solvent
mixture 35.
Changing the average molecular carbon content may be referred to as changing
the average
molecular weight. Increasing the average molecular carbon content also may be
referred to as
increasing the average molecular weight. Decreasing the average molecular
carbon content
may be referred to as decreasing the average molecular weight.
[00149] Changes in the chemical structure of hydrocarbon solvent mixture 35
may change
the asphaltene content of reservoir heavy oil product stream 72. For a
molecule with a given
number of carbon atoms, normal alkanes generally will produce a lower
asphaltene content
than iso-alkanes. Iso-alkanes generally will produce a lower asphaltene
content than
naphthenic hydrocarbons. Naphthenic hydrocarbons generally will produce a
lower asphaltene
content than aromatic hydrocarbons. The systems and methods according to the
present
disclosure may utilize this variation in asphaltene content with chemical
structure of
hydrocarbon solvent mixture 35 to change, or vary, the asphaltene content of
reservoir heavy
oil product stream 72.
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[001501 The systems and methods according to the present disclosure may
include
increasing a proportion of hydrocarbon solvent mixture 35 that comprises
chemical structures
that provide a (relatively) higher asphaltene content in reservoir heavy oil
product stream 72,
such as naphthenic hydrocarbons and/or aromatic hydrocarbons, to increase the
asphaltene
content of the reservoir heavy oil product stream. The systems and methods
according to the
present disclosure also may include increasing a proportion of hydrocarbon
solvent mixture 35
that comprises chemical structures that provide a (relatively) lower
asphaltene content in
reservoir heavy oil product stream 72, such as normal alkanes and/or iso-
alkanes, to decrease
the asphaltene content of the reservoir heavy oil product stream.
[00151] The control, regulation, and/or variation in the hydrocarbon solvent
mixture
composition may be accomplished in any suitable manner. For example, a
supplemental
solvent stream composition of supplemental solvent stream 31 may be varied to
control,
regulate, and/or vary the hydrocarbon solvent mixture composition. The
operation of surface
facility 40 may be varied to vary the hydrocarbon solvent mixture composition.
[00152] Figure 11 is a bar graph illustrating heavy end component deposition
within a
subterranean reservoir for various single-component hydrocarbon solvents at
two different
temperatures. Stated another way, Figure 11 illustrates a fraction,
proportion, or percentage of
heavy end components that initially may be present within a bituminous
hydrocarbon deposit
and that remain in a subterranean reservoir that may include the bituminous
hydrocarbon
deposit subsequent to solvent extraction of bituminous hydrocarbon deposit at
the given
temperatures by the given solvents.
[00153] As may be seen in Figure 11, increasing the carbon content of the
single-component
hydrocarbon solvents decreases the fraction of the heavy end components that
may remain
within the subterranean reservoir subsequent to the solvent-based recovery
process. Stated
another way, increasing the carbon content of the single-component hydrocarbon
solvents
increases the fraction of the heavy end components that may be produced from
the subterranean
reservoir via the solvent-based recovery process.
[00154] Figure 11 illustrates that increasing the temperature of the
solvent-based recovery
process decreases the fraction of the heavy end components that may remain
within the
subterranean reservoir. Thus, Figure 11 illustrates that both the carbon
content and the
temperature of the single-component hydrocarbon solvents may have a
significant impact on
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the production of heavy end components from a subterranean reservoir that may
include a
bituminous hydrocarbon deposit.
1001551 The systems and methods according to the present disclosure may
utilize a
multicomponent hydrocarbon solvent as the hydrocarbon solvent mixture 35.
Performing
solvent-based recovery processes with multicomponent hydrocarbon solvent
mixtures may
permit independent (or at least quasi-independent) selection of the
temperature of the solvent-
based recovery process, the pressure of the solvent-based recovery process,
and the proportion
of the heavy end components that may be produced during the solvent-based
recovery process.
1001561 The ability of the systems and methods according to the present
disclosure to
independently select the temperature of the solvent-based recovery process,
the pressure of the
solvent-based recovery process, and the proportion of the heavy end components
that may be
produced during the solvent-based recovery process is illustrated in Figures
12-13. Figure 12
is a table illustrating an average saturation temperature for three different
hydrocarbon solvent
mixtures at a pressure of 0.5 megapascals. The three different hydrocarbon
solvent mixtures
are designated Mix 1 , Mix2, and Mix3, and have average molecular carbon
contents of 5.65,
5.05, and 4.25, respectively. Figure 13 is a bar graph illustrating heavy end
component
deposition, which may include asphaltene deposition, within a subterranean
reservoir for the
three different hydrocarbon solvent mixtures of Figure 12.
1001571 As may be seen in Figures 12-13, decreasing the average molecular
carbon content
of the hydrocarbon solvent mixture decreases the average saturation
temperature of the
hydrocarbon solvent mixture at 0.5 megapascals. Decreasing the average
molecular carbon
content also increases the fraction of the heavy end components that remains
in the
subterranean reservoir after performing the solvent-based recovery process.
1001581 The data in Figures 12-13 are presented as examples to illustrate how
the systems
and methods according to the present disclosure may vary the composition of a
hydrocarbon
solvent mixture to vary the temperature, pressure, heavy end component, and/or
asphaltene
production of a solvent-based recovery process that utilizes the hydrocarbon
solvent mixture.
The specific hydrocarbon solvent mixtures and the pressure of 0.5 megapascals
are provide for
illustration purposes only. It is within the scope of the present disclosure
that other
hydrocarbon solvent mixtures that produce different average saturation
temperatures at 0.5
megapascals may be utilized in the disclosed systems and methods. The
disclosed systems and
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methods also may operate at pressures greater than and/or less than 0.5
megapascals.
[00159] Figures 11-13 illustrate the properties of various hydrocarbon
solvent mixtures that
may be formed from normal alkanes and/or heavy end deposition for these
mixtures. However,
it is to be understood that hydrocarbon solvent mixtures according to the
present disclosure
may include other components in addition to normal alkanes. These other
components may
include iso-alkanes, naphthenic hydrocarbons, olefin hydrocarbons, and/or
aromatic
hydrocarbons. In addition, the hydrocarbon solvent mixture initially may be
obtained from any
suitable source. As examples, the hydrocarbon solvent mixtures may include, or
be, a gas plant
condensate and/or crude oil refinery naphtha products.
[00160] The hydrocarbon solvent mixture may include a plurality of hydrocarbon
molecules
that defines an average molecular carbon content. Selecting the hydrocarbon
solvent mixture
may include selecting such that the average molecular carbon content has a
threshold value.
Examples of the threshold value of the average molecular carbon content
include average
molecular carbon contents of at least 2, at least 2.25, at least 2.5, at least
2.75, at least 3, at least
3.25, at least 3.5, at least 3.75, at least 4, at least 4.25, at least 4.5, at
least 4.75 at least 5, at
least 5.25, at least 5.5, at least 5.75, at least 6, at least 6.25, at least
6.5, at least 6.75, or at least
7. Additional examples of the threshold value of the average molecular carbon
content include
average molecular carbon contents of less than 12, less than 11.5, less than
11, less than 10.5,
less than 10, less than 9.5, less than 9, less than 8.5, less than 8, less
than 7.5, less than 7, less
than 6.5, less than 6, less than 5.5, or less than 5. Suitable ranges may
include combinations of
any upper and lower amount of average molecular carbon content ranges listed
above or any
number within or bounded by the average molecular carbon content ranges listed
above.
[00161] Selecting of the hydrocarbon solvent mixture may include selecting
such that the
hydrocarbon solvent mixture may include a first fraction that comprises a
first compound with
at least five carbon atoms and a second fraction that comprises a second
compound with at least
six carbon atoms. The first compound and the second compound each may comprise
at least
10 mole percent, at least 20 mole percent, at least 30 mole percent, at least
40 mole percent, at
least 50 mole percent, at least 60 mole percent, at least 70 mole percent, or
at least 80 mole
percent of the hydrocarbon solvent mixture. Suitable ranges may include
combinations of any
upper and lower amount of mole percent ranges listed above or any number
within or bounded
by the mole percent ranges listed above.
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[00162] As discussed with reference to Figures 12-13, the hydrocarbon solvent
mixture
composition may directly impact the average saturation temperature and/or the
vapor pressure
of the hydrocarbon solvent mixture. The selecting of the hydrocarbon solvent
mixture may
include selecting the hydrocarbon solvent mixture composition based, at least
in part, on a
desired temperature within the solvent extraction chamber and/or based upon a
desired pressure
within the solvent extraction chamber. As used herein, the temperature within
the solvent
extraction chamber (or "reservoir temperature") is the temperature of the
reservoir as measured
(or is as calculated if no in-situ sensors are available) near the injection
well. As used herein,
the pressure within the solvent extraction chamber (or "reservoir pressure")
is the pressure of
the reservoir as measured (or is as calculated if no in-situ sensors are
available) near the
injection well.
[00163] The production rate of the reservoir heavy oil product stream that is
produced may
be impacted by the temperature within the solvent extraction chamber, with
higher
temperatures yielding higher production rates. The desired temperature within
the solvent
extraction chamber may be based, at least in part, on a desired production
rate of the product
hydrocarbon stream. The pressure within the solvent extraction chamber may be
limited to a
threshold maximum pressure of the subterranean reservoir. The desired pressure
within the
solvent extraction chamber may be based, at least in part, on the threshold
maximum pressure
of the subterranean reservoir.
[00164] The selecting of the hydrocarbon solvent mixture may include
increasing the
average molecular carbon content of the hydrocarbon solvent mixture. The
average molecular
carbon content may be increased to increase the temperature (or based upon an
increase in the
desired temperature) within the subterranean reservoir. The average molecular
carbon content
may be increased to decrease the pressure (or based upon a decrease in the
desired pressure)
within the subterranean reservoir.
[00165] The selecting of the hydrocarbon solvent mixture may include
decreasing the
average molecular carbon content of the hydrocarbon solvent mixture. The
average molecular
carbon content may be decreased to decrease the temperature (or based upon a
decrease in the
desired temperature) within the subterranean reservoir. The average molecular
carbon content
may be decreased to increase the pressure (or based upon an increase in the
desired pressure)
within the subterranean reservoir.
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1001661 The selecting of the hydrocarbon solvent mixture may include selecting
a chemical
structure of the hydrocarbon solvent mixture. The hydrocarbon solvent mixture
may include
hydrocarbon molecules that have different chemical structures. The selecting
of the
hydrocarbon solvent mixture may include selecting the chemical structures
and/or a relative
.. proportion of the chemical structures such that the product hydrocarbon
stream has at least the
threshold asphaltene content. The selecting may include increasing a
proportion of the
hydrocarbon solvent mixture that comprises chemical structures that provide a
(relatively)
higher asphaltene content in the product hydrocarbon stream, such as
naphthenic hydrocarbons
and/or aromatic hydrocarbons, to increase the asphaltene content of the
product hydrocarbon
stream. The selecting of the hydrocarbon solvent mixture may include
increasing a proportion
of the hydrocarbon solvent mixture that comprises chemical structures that
provide a
(relatively) lower asphaltene content in the product hydrocarbon stream, such
as normal
alkanes and/or iso-alkanes, to decrease the asphaltene content of the product
hydrocarbon
stream. The selecting may include decreasing the normal alkane content of the
hydrocarbon
solvent mixture to increase the asphaltene content of the product hydrocarbon
stream.
1001671 Injecting the reservoir injection mixture may include injecting the
reservoir
injection mixture into the solvent extraction chamber. The injecting may
include injecting the
reservoir injection mixture into an injection well. The injection well may
extend within the
subterranean reservoir, may extend within the solvent extraction chamber, may
extend
proximal the solvent extraction chamber, may extend between a surface region
and the
subterranean reservoir, and/or may extend between the surface region and the
solvent
extraction chamber.
1001681 Injecting the reservoir injection mixture may include injecting at an
injection
temperature and/or at an injection pressure. Injecting the reservoir injection
mixture may
include injecting such that the reservoir injection mixture is a liquid
mixture at the injection
temperature and the injection pressure. However, it is preferred that the
injecting of the
reservoir injection mixture include where the reservoir injection mixture
include both the
hydrocarbon solvent mixture and steam and injecting such that the reservoir
injection mixture
is a vaporous mixture at the injection temperature and the injection pressure.
Injecting the
reservoir injection mixture may include injecting such that the reservoir
injection mixture is a
liquid-vapor mixture that includes both a liquid and a vapor at the injection
temperature and
the injection pressure. However, it is most preferred that the reservoir
injection mixture 32
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comprise both the hydrocarbon solvent mixture 35 and steam 50 and be injected
at near
azeotropic conditions and wherein the reservoir injection mixture is at least
90%, at least 95%
or essentially 100% vapor by weight at injection into the injection well 30.
Here the term near-
azeotropic conditions are preferably wherein the steam and hydrocarbon solvent
mixture is
within 30%+/-, 20%+/-, or 10%+/- of the azeotropic solvent molar fraction of
the steam and
the solvent as measured at the reservoir operating pressure. Alternatively,
the steam and
hydrocarbon solvent mixture is 70-110%, 70-100%, 80-100%, or 90 to 100% of the
azeotropic
solvent molar fraction of the steam and the solvent as measured at the
reservoir operating
pressure. When the hydrocarbon solvent mixture is the vaporous hydrocarbon
solvent mixture,
113 the injection temperature may be at, or near, a saturation temperature for
the vaporous
hydrocarbon solvent mixture at the injection pressure.
[001691 Producing the reservoir heavy oil product stream may include producing
the
reservoir heavy oil product stream from the subterranean reservoir, producing
the reservoir
heavy oil product stream from the solvent extraction chamber, and/or producing
the reservoir
heavy oil product stream to the surface region. This may include producing the
reservoir heavy
oil product stream from a production well. The production well may extend
within the
subterranean reservoir, may extend within the solvent extraction chamber, may
extend
proximal the solvent extraction chamber, may extend between a surface region
and the
subterranean reservoir, and/or may extend between the surface region and the
solvent
extraction chamber. The production well may be spaced apart from the injection
well. The
production well may be located below the injection well and/or may be located
vertically
deeper within the subterranean reservoir than the injection well.
[00170] Determining the asphaltene content of the reservoir heavy oil product
stream may
include determining the asphaltene content in any suitable manner. For
example, the
determining the asphaltene content may include indirectly determining the
asphaltene content
of the reservoir heavy oil product stream. The indirectly determining may
include measuring
a density of the product hydrocarbon stream and/or measuring a viscosity of
the product
hydrocarbon stream.
1001711 The determining of the asphaltene content of the reservoir heavy oil
product stream
may include performing a crude assay on a sample from the reservoir heavy oil
product stream.
The determining of the asphaltene content of the reservoir heavy oil product
stream may
include obtaining a gas chromatograph of the sample from the product
hydrocarbon stream.
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The asphaltene content may include performing a standard ASTM asphaltene test
such as
ASTM test number D3279. Other suitable alternative ASTM asphaltene test
methods include
ASTM test numbers D4055, D6560, and D7061. This may alternatively include
determining
the asphaltene content of any suitable portion of the reservoir heavy oil
product stream.
[00172] In embodiments, the process may comprise measuring a density of the
product
hydrocarbon stream comprising: determining a target density for the reservoir
heavy oil stream;
measuring an existing density of the reservoir heavy oil stream; and adjusting
the amount of
the hydrocarbon solvent mixture in the reservoir injection mixture to obtain
an actual density
of the reservoir heavy oil stream equal to the target density. In other
embodiments, the process
may comprise: determining a target density for the reservoir heavy oil stream;
measuring an
existing density of the reservoir heavy oil stream; and adjusting the
composition of the
hydrocarbon solvent mixture in the reservoir injection mixture to obtain an
actual density of
the reservoir heavy oil stream equal to the target density.
[00173] In embodiments, the process may comprise: determining a target
viscosity for the
reservoir heavy oil stream; measuring an existing viscosity of the reservoir
heavy oil stream;
and adjusting the amount of the hydrocarbon solvent mixture in the reservoir
injection mixture
to obtain an actual viscosity of the reservoir heavy oil stream equal to the
target viscosity. In
other embodiments, the process may comprise: determining a target viscosity
for the reservoir
heavy oil stream; measuring an existing viscosity of the reservoir heavy oil
stream; and
adjusting the composition of the hydrocarbon solvent mixture in the reservoir
injection mixture
to obtain an actual viscosity of the reservoir heavy oil stream equal to the
target viscosity.
[00174] Comparing the asphaltene content of the reservoir heavy oil product
stream to the
target asphaltene content may include comparing the asphaltene content of the
product
hydrocarbon stream to any suitable target, desired, and/or predetermined
asphaltene content
for the reservoir heavy oil product stream.
[00175] Adjusting the composition of the reservoir injection mixture 32 may
include
adjusting based, at least in part, on comparing the asphaltene content of the
reservoir heavy oil
product stream to the target asphaltene content. The target asphaltene content
may be a target
asphaltene content range, and the adjusting may include adjusting to maintain
the asphaltene
content of the product hydrocarbon stream within the target asphaltene content
range. The
reservoir heavy oil product stream may include a hydrocarbon solvent fraction
and a
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bituminous hydrocarbon fraction. The hydrocarbon solvent fraction may include,
comprise, or
be formed from the hydrocarbon solvent mixture that was injected. The
bituminous
hydrocarbon fraction may include, comprise, or be formed from the bituminous
hydrocarbon
deposit. Examples of lower limits for the target asphaltene content range
include lower limits
of at least 1 weight percent, at least 2 weight percent, at least 3 weight
percent, at least 4 weight
percent, at least 5 weight percent, at least 6 weight percent, at least 8
weight percent, at least
weight percent, at least 12 weight percent, at least 14 weight percent, or at
least 16 weight
percent of the bituminous hydrocarbon fraction. Examples of upper limits for
the target
asphaltene content range include upper limits of less than 30 weight percent,
less than 28 weight
10 percent, less than 26 weight percent, less than 24 weight percent, less
than 22 weight percent,
less than 20 weight percent, less than 18 weight percent, less than 16 weight
percent, less than
14 weight percent, less than 12 weight percent, less than 10 weight percent,
or less than 5
weight percent of the bituminous hydrocarbon fraction. Suitable ranges may
include
combinations of any upper and lower amount of weight percentage ranges listed
above or any
number within or bounded by the weight percentage ranges listed above.
[00176] The adjusting the composition of the reservoir injection mixture 32
also may
include adjusting to maintain the asphaltene content of the reservoir heavy
oil product stream
above the threshold asphaltene content. Examples of the threshold asphaltene
content include
threshold asphaltene contents of at least 1 weight percent, at least 2 weight
percent, at least 3
weight percent, at least 4 weight percent, at least 5 weight percent, at least
6 weight percent, at
least 8 weight percent, at least 10 weight percent, at least 12 weight
percent, at least 14 weight
percent, or at least 16 weight percent of the bituminous hydrocarbon fraction.
Suitable ranges
may include combinations of any upper and lower amount of weight percentage
ranges listed
above or any number within or bounded by the weight percentage ranges listed
above.
[00177] The subterranean reservoir may have a fluid permeability, and
deposition of
asphaltenes within the subterranean reservoir may impact, or decrease the
fluid permeability.
The adjusting the composition of the reservoir injection mixture 32 may
include adjusting to
maintain at least a threshold fluid permeability within the subterranean
reservoir. The threshold
fluid permeability may be determined based upon one or more characteristics of
the
subterranean reservoir and/or based upon a desired production rate of the
reservoir heavy oil
product stream from the subterranean reservoir.
[00178] The reservoir heavy oil product stream may include one or more
contaminants that
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may be present within and/or be generated from the bituminous hydrocarbon
deposit. These
contaminants may negatively impact the operation of equipment that may receive
and/or
process the product hydrocarbon stream. The adjusting the composition of the
reservoir
injection mixture 32 may include adjusting to maintain a concentration of the
one or more
contaminants below a threshold contaminant level in the reservoir heavy oil
product stream.
The threshold contaminant level may be selected such that the one or more
contaminants do
not have a negative impact on the operation of the equipment that may receive
and/or process
the product hydrocarbon stream. Examples of contaminants that may be present
within the
reservoir heavy oil product stream include heavy metals, vanadium, nickel,
nitrogen, and/or
sulfur heteroatoms and others.
[001791 The adjusting the composition of the reservoir injection mixture 32
may include
adjusting to maintain one or more material properties of the reservoir heavy
oil product stream
and/or of the bituminous hydrocarbon fraction of the reservoir heavy oil
product stream within
a desired range. The adjusting the composition of the reservoir injection
mixture 32 may
include adjusting to maintain the pipelineability of the reservoir heavy oil
product stream 72
or, more importantly, of the bitumen product stream 42. As another example,
the reservoir
heavy oil product stream may have a density at a given temperature (such as 5
degrees Celsius).
The adjusting the composition of the reservoir injection mixture 32 may
include adjusting the
viscosity to maintain the density within a target density range. The reservoir
heavy oil product
stream may have a viscosity at the given temperature. The adjusting the
composition of the
reservoir injection mixture 32 may include adjusting to maintain the viscosity
of the reservoir
heavy oil product stream within a target viscosity range. The adjusting the
composition of the
reservoir injection mixture 32 may include adjusting to produce a target
weight percent of the
asphaltenes from the bituminous hydrocarbon deposit. The adjusting the
composition of the
reservoir injection mixture 32 may include adjusting to produce at least 1, at
least 2, at least 5,
at least 10, at least 15, at least 20, or at least 25 weight percent of the
asphaltenes from the
bituminous hydrocarbon deposit. The adjusting the composition of the reservoir
injection
mixture 32 also may include adjusting to produce less than 99, less than 98,
less than 95, less
than 90, less than 85, less than 80, or less than 75 weight percent of the
asphaltenes from the
bituminous hydrocarbon deposit. Suitable ranges may include combinations of
any upper and
lower amount of weight percentage ranges listed above or any number within or
bounded by
the weight percentage ranges listed above.
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[00180] The adjusting the composition of the reservoir injection mixture 32
may include
adjusting to deposit a target weight percent of the asphaltenes within the
subterranean reservoir
during production. The adjusting the composition of the reservoir injection
mixture 32 may
include adjusting to deposit at least I, at least 2, at least 5, at least 10,
at least 15, at least 20, or
.. at least 25 weight percent of the asphaltenes within the subterranean
reservoir. The adjusting
the composition of the reservoir injection mixture 32 may include adjusting to
deposit less
than 99, less than 98, less than 95, less than 90, less than 85, less than 80,
or less than 75 weight
percent of the asphaltenes within the subterranean reservoir. Suitable ranges
may include
combinations of any upper and lower amount of weight percentage ranges listed
above or any
number within or bounded by the weight percentage ranges listed above.
[00181] The adjusting the composition of the reservoir injection mixture 32
may include
increasing the average molecular carbon content of the hydrocarbon solvent
mixture. The
average molecular carbon content may be increased to increase the asphaltene
content of the
reservoir heavy oil product stream. The average molecular carbon content may
be increased
to decrease deposition of asphaltenes within the subterranean reservoir, which
may increase
the fluid permeability of the subterranean reservoir. Contaminants may be
bound to and/or
produced with asphaltenes, and the average molecular carbon content may be
increased to
increase the concentration of contaminants within the reservoir heavy oil
product stream. The
average molecular carbon content may be increased to increase the viscosity of
the reservoir
heavy oil product stream. The average molecular carbon content may be
increased to increase
the density of the reservoir heavy oil product stream.
[00182] The adjusting the composition of the reservoir injection mixture 32
may include
decreasing the average molecular carbon content of the hydrocarbon solvent
mixture. The
average molecular carbon content may be decreased to decrease the asphaltene
content of the
reservoir heavy oil product stream. The average molecular carbon content may
be decreased
to increase deposition of asphaltenes within the subterranean reservoir, which
may decrease
the fluid permeability of the subterranean reservoir. Contaminants may be
bound to and/or
produced with asphaltenes, and the average molecular carbon content may be
decreased to
decrease the concentration of contaminants within the reservoir heavy oil
product stream. The
average molecular carbon content may be decreased to decrease the viscosity of
the reservoir
heavy oil product stream. The average molecular carbon content may be
decreased to decrease
the density of the reservoir heavy oil product n stream.
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[00183] The adjusting the composition of the reservoir injection mixture 32
also may
include adjusting a chemical structure of the hydrocarbon solvent mixture. The
hydrocarbon
solvent mixture may include a plurality of hydrocarbon molecules that have
different chemical
structures. The adjusting the composition of the reservoir injection mixture
32 may include
adjusting the chemical structures and/or a relative proportion of the chemical
structures such
that the reservoir heavy oil product stream has the target asphaltene content.
The adjusting the
composition of the reservoir injection mixture 32 may include increasing a
proportion of the
hydrocarbon solvent mixture that comprises chemical structures that provide a
(relatively)
higher asphaltene content in the reservoir heavy oil product stream, such as
naphthenic
hydrocarbons and/or aromatic hydrocarbons, to increase the asphaltene content
of the reservoir
heavy oil product stream. The adjusting the composition of the reservoir
injection mixture 32
also may include increasing a proportion of the hydrocarbon solvent mixture
that comprises
chemical structures that provide a (relatively) lower asphaltene content in
the reservoir heavy
oil product stream, such as normal alkanes and/or iso-alkanes, to decrease the
asphaltene
content of the reservoir heavy oil product stream. The adjusting the
composition of the
reservoir injection mixture 32 may include decreasing the normal alkane
content of the
hydrocarbon solvent mixture to increase the asphaltene content of the
reservoir heavy oil
product stream.
[00184] Based on the disclosure and teachings herein, the following are
specific
embodiments of the processes disclosed.
Embodiments:
[00185] Embodiment 1. A process for recovery of heavy oil from a subterranean
reservoir,
the process comprising:
a) determining a target subterranean reservoir operating pressure;
b) determining a target subterranean reservoir operating temperature;
c) determining a target asphaltene content for a produced reservoir heavy
oil
product stream from the subterranean reservoir;
d) adjusting the composition of a hydrocarbon solvent mixture to achieve
the
asphaltene content in step c) under the conditions of steps a) and b);
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e)
determining the azeotropic/minimum dew point steam content of the
hydrocarbon solvent mixture in the vapor phase under the conditions of steps
a) and b);
at an actual subterranean reservoir operating pressure and an actual
subterranean
reservoir operating temperature, co-injecting a reservoir injection mixture in
the vapor phase
into the subterranean reservoir comprising steam and the hydrocarbon solvent
mixture, wherein
the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon
solvent
mixture is 70-110% of the azeotropic solvent molar fraction of the steam and
the hydrocarbon
solvent mixture as determined in step e);
g) recovering a reservoir heavy oil stream from the subterranean
reservoir; and
h) producing a
bitumen product stream from the reservoir heavy oil product
stream.
[00186] Embodiment 2. The process of Embodiment 1, wherein the target
subterranean
reservoir operating temperature is the existing subterranean reservoir
operating temperature.
[00187] Embodiment 3. The process of Embodiment 1, further comprising:
- determining an increased target subterranean reservoir operating temperature
which is greater than the existing subterranean reservoir operating
temperature;
-
increasing the content of the higher boiling point hydrocarbon compounds of
the hydrocarbon solvent mixture to produce a revised reservoir injection
mixture wherein the
hydrocarbon solvent molar fraction of the combined steam and hydrocarbon
solvent mixture is
70-110% of the azeotropic solvent molar fraction of the steam and the
hydrocarbon solvent
mixture at the increased target subterranean reservoir operating temperature;
- increasing the actual subterranean reservoir operating temperature to the
increased target subterranean reservoir operating temperature; and
- co-
injecting the revised reservoir injection mixture in the vapor phase into the
subterranean reservoir.
[00188] Embodiment 4. The process of Embodiment 1, further comprising:
- determining a decreased target subterranean reservoir operating temperature
which is lower than the existing subterranean reservoir operating temperature,
-
increasing the content of the lower boiling point hydrocarbon compounds of the
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hydrocarbon solvent mixture to produce a revised reservoir injection mixture
wherein the
hydrocarbon solvent molar fraction of the combined steam and hydrocarbon
solvent mixture is
70-110% of the azeotropic solvent molar fraction of the steam and the
hydrocarbon solvent
mixture at the decreased target subterranean reservoir operating temperature;
- decreasing the actual subterranean reservoir operating temperature to the
decreased target subterranean reservoir operating temperature; and
- co-injecting the revised reservoir injection mixture in the vapor phase
into the
subterranean reservoir.
[00189] Embodiment 5. The process of Embodiment 1, further comprising:
- determining the actual asphaltene content of the reservoir heavy oil product
stream;
- comparing the actual asphaltene content of the reservoir heavy oil
product
stream to the target asphaltene content of the reservoir heavy oil product
stream;
- increasing the content of the higher boiling point hydrocarbon compounds
of
the hydrocarbon solvent mixture to produce a revised reservoir injection
mixture wherein the
hydrocarbon solvent molar fraction of the combined steam and hydrocarbon
solvent mixture is
70-110% of the azeotropic solvent molar fraction of the steam and the
hydrocarbon solvent
mixture at the actual subterranean reservoir operating temperature;
- co-injecting the revised reservoir injection mixture into the
subterranean
reservoir; and
- recovering the reservoir heavy oil product stream from the subterranean
reservoir.
[00190] Embodiment 6. The process of Embodiment 1, further comprising:
- determining the actual asphaltene content for the reservoir heavy oil
product
stream;
- comparing the actual asphaltene content of the reservoir heavy oil
product
stream to the target asphaltene content of the reservoir heavy oil product
stream;
-
increasing the content of the lower boiling point hydrocarbon compounds of the
hydrocarbon solvent mixture to produce a revised reservoir injection mixture
wherein the
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wherein the hydrocarbon solvent molar fraction of the combined steam and
hydrocarbon
solvent mixture is 70-110% of the azeotropic solvent molar fraction of the
steam and the
hydrocarbon solvent mixture at the actual subterranean reservoir operating
temperature;
- co-injecting the revised reservoir injection mixture into the subterranean
reservoir; and
- recovering the reservoir heavy oil product stream from the subterranean
reservoir.
[00191] Embodiment 7. The process of Embodiment 1, further comprising:
- determining the actual asphaltene content of the reservoir heavy oil
product
stream;
- comparing the actual asphaltene content of the reservoir heavy oil
product
stream to the target asphaltene content for the reservoir heavy oil product
stream; and
- when the actual asphaltene content of the reservoir heavy oil product
stream is
higher than the target asphaltene content for the reservoir heavy oil product
stream, increasing
the content of the lower boiling point hydrocarbon compounds of the
hydrocarbon solvent
mixture.
[00192] Embodiment 8. The process of Embodiment 1, further comprising:
- determining the actual asphaltene content of the reservoir heavy oil product
stream;
- comparing the actual asphaltene content of the reservoir heavy oil product
stream to the target asphaltene content for the reservoir heavy oil product
stream; and
- when the
actual asphaltene content of the reservoir heavy oil product stream is
lower than the target asphaltene content for the reservoir heavy oil product
stream, increasing
the content of the higher boiling point hydrocarbon compounds of the
hydrocarbon solvent
mixture.
[00193] Embodiment 9. The process of any one of Embodiments 3, 5 and 8,
wherein the
higher boiling point hydrocarbon compounds are the CS+ compounds of the
hydrocarbon
solvent mixture.
[00194] Embodiment 10. The process of any one of Embodiments 4, 6 and 7,
wherein the
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lower boiling point hydrocarbon compounds are the CI - C4 compounds of the
hydrocarbon
solvent mixture.
[00195] Embodiment 11. The process of Embodiment 1, further comprising:
- determining the actual asphaltene content of the reservoir
heavy oil product
stream;
- comparing the actual asphaltene content of the reservoir heavy oil product
stream to the target asphaltene content for the reservoir heavy oil product
stream; and
- when the actual asphaltene content of the reservoir heavy oil product
stream is
higher than the target asphaltene content for the reservoir heavy oil product
stream, decreasing
the content of the aromatic compounds of the hydrocarbon solvent mixture.
[00196] Embodiment 12. The process of Embodiment 11, further comprising:
- decreasing the olefinic or naphthenic content of the hydrocarbon solvent
mixture.
[00197] Embodiment 13. The process of Embodiment 11 or 12, further comprising:
- increasing the paraffinic content of the hydrocarbon solvent mixture.
[00198] Embodiment 14. The process of Embodiment 1, further comprising:
- determining the actual asphaltene content of the reservoir heavy oil
product
stream;
- comparing the actual asphaltene content of the reservoir heavy oil product
stream to the target asphaltene content for the reservoir heavy oil product
stream; and
- when the actual asphaltene content of the reservoir heavy oil product
stream is
lower than the target asphaltene content for the reservoir heavy oil product
stream, increasing
the content of the aromatic compounds of the hydrocarbon solvent mixture.
[00199] Embodiment 15. The process of Embodiment 14, further comprising:
- increasing the olefinic or naphthenic content of the hydrocarbon solvent
mixture.
1002001 Embodiment 16. The process of Embodiment 14 or 15, further comprising:
- decreasing the paraffinic content of the hydrocarbon solvent mixture.
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[00201] The disclosed systems and methods may refer to producing certain
proportions,
fractions, and/or percentages of heavy end components, such as asphaltenes,
that may be
present within a bituminous hydrocarbon deposit. The systems and methods also
may refer to
depositing, or retaining, certain proportions, fractions, and/or percentages
of the heavy end
components in a subterranean reservoir that may include the bituminous
hydrocarbon deposit.
[00202] The disclosed systems and methods may not be utilized over, or to
produce, an
entire bituminous hydrocarbon deposit. It may be uneconomical, or even
impossible, to
perform the disclosed systems and methods within certain regions of the
bituminous
hydrocarbon deposit. The disclosed systems and methods may be performed over a
period of
several years. Other recovery processes may be utilized within certain
portions of a given
bituminous hydrocarbon deposit. Thus,
the described proportions, fractions, and/or
percentages may refer to proportions, fractions, and/or percentages of a
produced portion (or
fraction) of the bituminous hydrocarbon deposit and not to proportions,
fractions, and/or
percentages of the entire bituminous hydrocarbon deposit. The produced portion
may include
a portion of the bituminous hydrocarbon deposit that is produced utilizing the
disclosed systems
and methods and/or a portion of the bituminous hydrocarbon deposit that is
produced at a given
point in time (or over a given period of time) utilizing the disclosed systems
and methods.
[00203] In the present disclosure, several examples have been discussed and/or
presented in
the context of flow diagrams, or flow charts, in which the methods are shown
and described as
a series of blocks, or steps. Unless specifically set forth in the
accompanying description, the
order of the blocks may vary from the illustrated order in the flow diagram,
including with two
or more of the blocks (or steps) occurring in a different order and/or
concurrently.
Industrial Applicability
[00204] The systems and methods disclosed in the present disclosure are
applicable to the
oil and gas industry.
[00205] It is
believed that the following claims particularly point out certain combinations
and subcombinations that are novel and non-obvious. Other
combinations and
subcombinations of features, functions, elements and/or properties may be
claimed through
amendment of the present claims or presentation of new claims in this or a
related application.
Such amended or new claims, whether different, broader, narrower, or equal in
scope to the
original claims, are also regarded as included within the subject matter of
the present disclosure.
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